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NEW YORK STATE ELECTRIC & GAS CORPORATION
(Registrant)
FORM 10-K
---------
ANNUAL REPORT
For Fiscal Year Ended December 31, 1993
To
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
TABLE OF CONTENTS
Page
PART I
Item 1. Business
(a) General development of business. . . . . . . . . 3
Rates and regulatory matters . . . . . . . . . . 3
Diversification. . . . . . . . . . . . . . . . . 5
Restructuring. . . . . . . . . . . . . . . . . . 6
(b) Financial information about industry segments . . 6
(c) Narrative description of business
Principal business . . . . . . . . . . . . . . . 7
New product or segment . . . . . . . . . . . . . 9
Sources and availability of raw materials. . . 10
Franchises . . . . . . . . . . . . . . . . . . .11
Seasonal business. . . . . . . . . . . . . . . .11
Working capital items. . . . . . . . . . . . . .11
Single customer. . . . . . . . . . . . . . . . .11
Backlog of orders. . . . . . . . . . . . . . . .11
Business subject to renegotiation. . . . . . . .11
Competitive conditions . . . . . . . . . . . . .11
Research and development . . . . . . . . . . . .13
Environmental matters. . . . . . . . . . . . . .13
Water quality. . . . . . . . . . . . . . . . .14
Air quality. . . . . . . . . . . . . . . . . .14
Waste disposal . . . . . . . . . . . . . . . .16
Number of employees. . . . . . . . . . . . . . .18
(d) Financial information about foreign and domestic
operations and export sales. . . . . . . . . .18
Item 2. Properties . . . . . . . . . . . . . . . . . . . . .18
Item 3. Legal proceedings. . . . . . . . . . . . . . . . . .19
Item 4. Submission of matters to a vote of security holders.23
Executive officers of the Registrant . . . . . . . . . . . . .23
PART II
Item 5. Market for Registrant's common stock and related
stockholder matters. . . . . . . . . . . . . . . .25
Item 6. Selected financial data. . . . . . . . . . . . . . .26
Principal sources of electric and natural gas revenues . . . .26
Item 7. Management's discussion and analysis of financial
condition and results of operations. . . . . . . .27
TABLE OF CONTENTS (Cont'd)
Page
Item 8. Financial statements and supplementary data. . . . .45
Financial Statements
Consolidated Statements of Income. . . . . . . . .45
Consolidated Balance Sheets. . . . . . . . . . . .46
Consolidated Statements of Cash Flows. . . . . . .48
Consolidated Statements of Changes in
Common Stock Equity. . . . . . . . . . . . . . .49
Notes to Consolidated Financial Statements . . . . .50
Report of Independent Accountants. . . . . . . . . .74
Financial Statement Schedules
V. Property, Plant, and Equipment . . . . . . .75
VI. Accumulated Depreciation of Property,
Plant, and Equipment . . . . . . . . . . .78
VIII. Allowance for Doubtful Accounts-Accounts
Receivable . . . . . . . . . . . . . . . .81
Item 9. Changes in and disagreements with accountants on
accounting and financial disclosure. . . . . . . .82
PART III
Item 10. Directors and executive officers of the Registrant .82
Item 11. Executive compensation . . . . . . . . . . . . . . .82
Item 12. Security ownership of certain beneficial owners
and management . . . . . . . . . . . . . . . . . .82
Item 13. Certain relationships and related transactions . . .82
PART IV
Item 14. Exhibits, financial statement schedules, and
reports on Form 8-K
(a) List of documents filed as part of this report
Financial statements . . . . . . . . . . . . .82
Financial statement schedules. . . . . . . . .82
Exhibits
Exhibits delivered with this report. . . . .83
Exhibits incorporated herein by reference. .83
(b) Reports on Form 8-K. . . . . . . . . . . . . . .88
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . .89
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
(Mark one)
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended December 31, 1993.
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from to .
Commission file number 1-3103-2.
NEW YORK STATE ELECTRIC & GAS CORPORATION
(Exact name of Registrant as specified in its charter)
New York 15-0398550
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
P. O. Box 3287, Ithaca, New York 14852-3287
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (607) 347-4131
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange on
Title of each class which registered
First Mortgage Bonds, 7 5/8% Series
due 2001 (Due November 1, 2001) New York Stock Exchange
First Mortgage Bonds, 8 5/8% Series
due 2007 (Due November 1, 2007) New York Stock Exchange
3.75% Cumulative Preferred Stock
(Par Value $100) New York Stock Exchange
7.40% Cumulative Preferred Stock
(Par Value $25) New York Stock Exchange
Adjustable Rate Cumulative Preferred
Stock, Series B (Par Value $25) New York Stock Exchange
Common Stock (Par Value $6.66 2/3) New York Stock Exchange
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
Securities registered pursuant to Section 12(g) of the Act:
Title of Class
4 1/2% Cumulative Preferred Stock (Series 1949) (Par Value $100)
4.15% Cumulative Preferred Stock (Par Value $100)
4.40% Cumulative Preferred Stock (Par Value $100)
4.15% Cumulative Preferred Stock (Series 1954) (Par Value $100)
* * * * * * * * * * *
Indicate by check mark whether the Registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the Registrant was required to
file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X . No .
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein,
and will not be contained, to the best of Registrant's knowledge,
in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this
Form 10-K [ X ].
* * * * * * * * * * *
The aggregate market value as of February 28, 1994 of the
common stock held by non-affiliates of the Registrant was
$1,932,112,936.
Common stock - 70,903,227 shares outstanding as of February
28, 1994.
DOCUMENTS INCORPORATED BY REFERENCE
Document 10-K Part
The Company has incorporated by reference
certain portions of its Proxy Statement
dated March 31, 1994 which will be filed
with the Commission prior to April 30, 1994. III
PART I
Item 1. Business
(a) General development of business
New York State Electric & Gas Corporation (Company) was
organized under the laws of the State of New York in 1852.
The following general developments have occurred in the
business of the Company since January 1, 1993:
Rates and regulatory matters
Rate Matters
In September 1993, the Company reached a three-year electric
and natural gas rate settlement agreement (Agreement) with the
Public Service Commission of the State of New York (PSC). The
new electric and natural gas rates became effective September 4,
1993.
The allowed return on equity is 10.8% in year one, 11.4% in
year two, and 11.4% (subject to an indexing mechanism) in year
three. Shareholders will be allowed to keep 100% of any earnings
in excess of the allowed return in year one. Shareholders and
customers will share, on a 50%/50% basis, any earnings in excess
of the allowed return in years two and three.
The Agreement also includes a modified revenue decoupling
mechanism (RDM) for electric sales. Rates are based on sales
forecasts. Since actual sales may differ significantly from
forecasted sales because of conservation efforts, unusual
weather, or changing economic conditions, the revenue collected
may be more or less than forecast. Subject to the caps described
below, the modified RDM will let the Company adjust for most of
the differences between forecasted and actual sales. For
example, if revenues exceed the forecast for a given year, the
excess would be passed back to customers in a future year. If
revenues are below the forecast, customers would receive a
surcharge in a future year. The Company will share excesses or
shortfalls from most large commercial and industrial sales
revenues on a 70%/30% (customer/stockholder) basis.
Customer savings for production and transmission operating
costs of $21 million will be imputed over three years, $7 million
each year, whether or not they are realized.
Incentives for customer service, production cost, and
demand-side management (DSM) could increase the allowed return to
12.3% or decrease it to 9.95% in year one, increase it to 13.05%
or decrease it to 10.4% in year two, and increase it to 13.25% or
decrease it to 10.2% in year three.
The electric and natural gas rate increases discussed below
represent eleven months for year one and twelve months for years
two and three.
The estimated total electric price increases below include
base rate increases allowed by the Agreement plus estimates of
fuel and purchased power increases which will be collected
through the Fuel Adjustment Clause (FAC). Actual fuel and
purchased power costs could vary from estimates causing the
estimated FAC and total electric price increases below to change.
Base Rate Estimated FAC Total Electric
(Dollar Amounts in Millions)
Year 1 $60.5 4.4% $39.1 3.0% $99.6 7.4%
Year 2 $70.3 4.8% $39.2 2.8% $109.5 7.6%
Year 3 $57.4 3.6% $30.4 2.0% $87.8 5.6%
The natural gas base rate increases allowed by the Agreement
are $7.5 million, or 2.9%, $8.2 million, or 3.0%, and $7.2
million, or 2.5%, in years one, two, and three, respectively.
They do not include changes in natural gas costs, which will be
collected through the Gas Adjustment Clause. Natural gas costs
can be expected to rise and fall with overall natural gas market
conditions. Such fluctuations will affect the total natural gas
price increases.
The Agreement also provides for the stated electric and
natural gas base rate increases to be adjusted up or down in the
second and third years, as well as the year after the Agreement
period (year four). These adjustments will depend on several
factors, such as electric sales and incentive mechanisms. The
Agreement provides that no cap would apply to any downward
revision to base rates for electric and natural gas service. The
electric base rate increases could be increased by up to 1.5% in
years two and three and 1.6% in year four (the caps). The
natural gas base rate increases could also be increased by up to
1% in year two and 1.2% in year three. The Agreement does not
specify a cap for natural gas base rates for year four.
Flexible, Negotiable Rate Tariffs
A major challenge to the Company's Electric Business Unit is
to retain and grow its industrial base. The competitive energy
supply options currently available to the Company's industrial
customers include self-generation, shifting production to plants
in other locations, or relocation. During 1993, the Company
received PSC approval for a flexible, negotiable rate tariff for
some of its high-use industrial customers. Discounts negotiated
in agreements under this tariff are not expected to have a
material effect on the Company's 1994 earnings. Two agreements
have been negotiated which eliminated threats of self-generation
and relocation.
The PSC currently has a generic proceeding to study the
broad subject of flexible, competitive rates, and will establish
guidelines for the Company and other New York State utilities
during 1994.
In November 1993, the Company filed with the PSC an
additional flexible, negotiable rate tariff to address
opportunities for new load. The proposed tariff is for large
additions to load (at least 500 kilowatts [kw]) for new or
existing industrial and some commercial customers. The tariff
will assist the Company in attracting new customers whose
location or expansion decisions are influenced by electricity
costs. Smaller customers will be assisted by a concurrent
proposal to increase the Company's existing economic development
incentives by one cent per kilowatt-hour. The Company has
proposed and will continue to propose revisions or additional
tariffs to respond to the opportunities or risks that develop in
a changing electric utility industry.
Federal Energy Regulatory Commission (FERC) Order 636
A major challenge to the Company's Gas Business Unit is FERC
Order 636, which became effective in November 1993, and requires
interstate natural gas pipeline companies to offer customers
unbundled or separate services equivalent to their former sales
service. With the unbundling of services, primary responsibility
for reliable natural gas supply will shift from interstate
pipeline companies to local distribution companies, such as the
Company. This should result in increased direct access to low
cost natural gas supplies by local distribution companies and end
users. One goal of FERC Order 636 is to provide equitable access
to interstate pipeline capacity. FERC Order 636 will
substantially restructure the interstate natural gas market and
intensify competition within the natural gas industry. FERC
Order 636 will allow the Company, subject to PSC approval, to
restructure rates and provide multiple service options to its
customers.
In July 1993, certain interstate pipelines serving the
Company began implementing restructured services in compliance
with FERC Order 636. The remaining pipelines implemented
restructured services by November 1993. As a result of these
restructuring changes, pipelines have incurred and will continue
to incur transition costs. These transition costs include those
associated with restructuring existing natural gas supply
contracts, the unrecovered natural gas cost that would otherwise
have been billable to pipeline customers under previously
existing rules, costs of assets needed to implement the order,
and stranded investment costs. FERC Order 636 allows pipelines
to recover all prudently incurred costs from their customers.
The Company's liability for transition costs will be based on the
pipelines' filings with FERC to recover transition costs. Only a
few of those filings have been made. The Company recorded an
estimated liability for transition costs of approximately $29
million. The Company also recorded a deferred asset for that
amount since it is currently recovering transition costs from its
customers through its gas adjustment clause and believes that
such costs will continue to be recoverable from its customers.
Diversification
Diversification will play an important role in the Company's
future. While the strength of the Company's core electric and
natural gas businesses remains its focus, and while the Company
will not compromise its financial integrity, it is actively
evaluating a number of corporate development opportunities for
investment to help augment future earnings and dividend growth.
In April 1992, the PSC issued an order allowing the Company to
invest up to 5% of its consolidated capitalization (approximately
$175 million at December 31, 1993) in one or more subsidiaries
that may engage or invest in energy-related or environmental
services businesses and provide related services. In May 1993,
NGE Enterprises, Inc. (NGE), a wholly-owned subsidiary of the
Company, formed a computer software company, EnerSoft Corporation
(EnerSoft), to produce and market software applications for
natural gas utilities in the post-FERC Order 636 environment.
This represents NGE's initial diversified investment.
In October 1993, EnerSoft began a strategic alliance with
the New York Mercantile Exchange to develop an information
superhighway that will provide the natural gas industry with a
single system for monitoring and trading natural gas and pipeline
capacity in the North American market. NGE invested
approximately $9 million in EnerSoft through February 1994.
The Company and NGE plan to develop two natural gas storage
projects. One of the projects, which will be regulated by the
PSC, is expected to cost approximately $14 million and will be
used to supplement the Company's natural gas supply.
Construction of this project is scheduled to begin in 1994 and it
is expected to be operating for the 1995-96 heating season. The
other project, which will be regulated by the FERC, is an equal
partnership between NGE and ANR Storage, Inc., and is expected to
cost approximately $44 million in total. The entire capacity of
this project will be marketed to local distribution companies and
non-utility generator (NUG)s, as well as marketers, producers,
and end users of natural gas. Construction of this project is
scheduled to begin in 1995 and it is expected to be operating for
the 1996-1997 heating season.
Restructuring
In the fourth quarter of 1993, the Company recorded a $26
million restructuring charge. The corporate restructuring will
reorganize the way the Company delivers services to its electric
and natural gas customers beginning in March 1994. The
restructuring reduced 1993 earnings available for common stock by
approximately $17.2 million or 25 cents per share. Included in
this amount are $13.2 million for a voluntary early retirement
program, $3.2 million for an involuntary severance program, and
$.8 million for the elimination and closing of electric and
natural gas operations facilities statewide. During 1994, the
restructuring resulted in a work force reduction throughout the
organization of approximately 600, the elimination of customer
walk-in services at 28 satellite locations, and the closing of up
to 10 electric and natural gas operations facilities statewide.
The work force reduction was accomplished through a voluntary
early retirement program (See Note 7 to the Consolidated
Financial Statements on page 60) and an involuntary severance
program. 384 employees accepted the early retirement program.
(b) Financial information about industry segments
See Note 11 to the Consolidated Financial Statements on
page 72.
(c) Narrative description of business
(i) Principal business
The Company's principal business is generating, purchasing,
transmitting, and distributing electricity and purchasing,
transporting, and distributing natural gas. The service
territory, 99% of which is located outside the corporate limits
of cities, is in the central, eastern, and western parts of the
State of New York. The service territory has an area of
approximately 19,500 square miles, and a population of 2,400,000.
The larger cities in which the Company serves both electricity
and natural gas are Binghamton, Elmira, Auburn, Geneva, Ithaca,
and Lockport. The Company serves approximately 790,000 electric
retail customers and 226,000 natural gas retail customers. Its
service territory reflects a diversified economy, including high-
tech firms, light industry, agriculture, colleges and
universities, and recreational facilities. No customer accounts
for 5% or more of either electric or natural gas revenues. For
the years 1993, 1992, and 1991, 85%, 86%, and 88%, respectively,
of operating revenue was derived from electric service and 15%,
14%, and 12%, respectively, was derived from natural gas service.
The 1993-1994 winter peak load of 2,618,000 kw, was set on
January 19, 1994. This is 21,000 kw more than the previous all
time peak of 2,597,000 kw set during the 1989-1990 winter on
December 21, 1989. Power supply capability to meet peak loads is
currently 3,194,430 kw. This is composed of 2,656,700 kw of
generating capacity (90% coal-fired, 7% nuclear, and 3%
hydroelectric) and 848,730 kw of purchases offset by 311,000 kw
of firm sales. The purchases are composed of 362,280 kw from
NUGs and 486,450 kw from the New York Power Authority (NYPA).
Most purchases from NYPA are hydroelectric power.
In June 1989, New York City, the Counties of Westchester,
Nassau, and Suffolk, and their respective municipal distribution
agencies, commenced Article 78 proceedings in the Supreme Court
of the State of New York (New York County) (Court) against NYPA
to set aside NYPA's contracts expiring in the year 2007 with the
Company and two other utilities for the post January 1, 1990
allocation of NYPA hydroelectric power. The Company has
intervened in these proceedings to protect its contractual
entitlement. In November 1990, the Court issued a decision
granting various motions and dismissing the Article 78
proceedings. On December 29, 1992, the Appellate Division, First
Department unanimously affirmed the decision. On October 12,
1993, the Court of Appeals of the State of New York rejected a
motion for leave to appeal to that court.
The Company has on line and under contract 362 megawatts
(mw) of NUG power. In addition, another 240 mw of NUG power is
under construction. The Company is required to make payments
under these contracts only for the power it receives. During
1993, 1992, and 1991, the Company purchased approximately $138
million, $71 million, and $30 million, respectively, of NUG
power. The Company estimates that it will purchase
approximately $255 million, $291 million, and $335 million of NUG
power for the years 1994, 1995, and 1996, respectively.
Increases in NUG power purchase costs are expected to be a
significant contributor to price increases over the next three
years.
As part of the Company's effort to meet competition and
minimize future price increases associated with uneconomical
power purchases from NUGs, it negotiated the termination of two
cogeneration projects. This effort, along with the termination
of NUG contracts due to developers' failures to meet contract
obligations, will save customers nearly $1 billion over the terms
of the contracts. The Company has also recently negotiated
amendments with two NUGs whereby the Company may direct the NUGs
to reduce their output or shut down for limited periods each
year. During these periods, lower-cost generation will replace
the NUG energy and result in additional customer savings. The
Company is negotiating with other NUGs for similar amendments.
As part of the Company's effort to reduce costs, one of two
generating units at each of its Goudey and Greenidge Generating
Stations will be placed on long-term cold standby. These actions
are being taken because the abundance of power in the Northeast
has driven down wholesale prices. These units will continue to
be utilized to provide electrical system support.
The Company has implemented a number of demand-side
management (DSM) programs. As a result of its three-year rate
settlement agreement (See Item 1(a)-Rates and regulatory matters
- - Rate Matters), incentives earned for conducting efficient DSM
programs were reduced from 15% to 5% of the net resource savings
achieved by these DSM programs. For 1994, the Company expects to
earn approximately $3 million in incentives as a result of these
DSM programs.
In 1993, the Company's customers saved approximately 282
million kilowatt-hours (kwh) on an annualized basis through the
Company's DSM programs. The implementation of these programs
cost $48 million in 1993 and will cost approximately $16 million
in 1994 with estimated customer savings of 113 million kwh on an
annualized basis. The Company has approximately $73 million and
$44 million of deferred DSM program costs on the Consolidated
Balance Sheets at December 31, 1993, and 1992, respectively. The
two-year (1993-1994) DSM plan, which has received PSC approval,
has been modified to improve cost-effectiveness and reduce rate
impacts.
On January 19, 1994, the Company experienced its 1993-1994
maximum peak daily sendout for natural gas of 431,756 dekatherms.
This is 69,175 dekatherms greater than the 1991-1992 peak of
362,581 dekatherms set on January 16, 1992.
The following table provides information on the Company's
estimated sources and uses of funds for 1994-1996. This forecast
is subject to periodic review and revision, and actual
construction costs may vary because of revised load estimates,
imposition of additional regulatory requirements, and the
availability and cost of capital.
1994 1995 1996 Total
---- ---- ---- -----
Sources of funds (Millions)
Internal funds $254 $265 $269 $788
Long-term financing
Debt and stock proceeds 413 141 80 634
Debt proceeds held in trust 34 8 - 42
---- ---- ---- -----
Net financing proceeds 447 149 80 676
Increase (decrease) in
short-term debt (50) - - (50)
Decrease (increase) in
temporary cash investments 89 (69) (52) (32)
---- ---- ---- ------
Total $740 $345 $297 $1,382
==== ==== ==== ======
Uses of funds
Construction
Cash expenditures $202 $193 $193 $588
AFDC 8 7 7 22
---- ---- ---- ------
Total construction 210 200 200 610
Retirement of securities and
sinking fund obligations 501 108 63 672
Working capital and deferrals 29 37 34 100
---- ---- ---- ------
Total $740 $345 $297 $1,382
==== ==== ==== ======
As shown in the preceding table, internal sources of funds
represent 129% of construction expenditures for 1994-1996.
Capital expenditures for 1994-1996 have been significantly
reduced from previously forecasted levels. This represents one
of many actions the Company is taking to address competition (See
Item 1(c)(x)-Competitive conditions). Capital expenditures for
1994-1996 will be primarily for extension of service, necessary
improvements at existing facilities, and compliance with the
Clean Air Act Amendments of 1990 (See Item 1(c)(xii)-
Environmental matters). The Company forecasts that its current
reserve margin, coupled with more efficient use of energy and
generation from NUGs, will eliminate the need for additional
generating capacity until after the year 2005.
(ii) New product or segment
(See Item 1(a)-Diversification.)
(iii) Sources and availability of raw materials
Electric
In 1993, approximately 90% of the Company's generation was
coal-fired steam electric, 8% nuclear and 2% hydroelectric power.
About 37% of the Company's steam electric generation in 1993 was
supplied from its one-half share of the output from the Homer
City Generating Station, which is owned in common with
Pennsylvania Electric Company. An additional 34% was supplied
from the Company's Kintigh Generating Station, and the remaining
29% was supplied from its other generating stations which are
located in New York State.
Coal
Coal for the New York generating stations is obtained
primarily from Pennsylvania and West Virginia. Of the 3.2
million tons of coal purchased for the New York generating
stations in 1993, approximately 46% was purchased under
contract and the balance on the open market. Coal purchased
under contract is expected to be approximately 53% of the
estimated 3.1 million tons to be purchased in 1994.
The annual coal requirement for the Homer City
Generating Station is approximately four million tons, the
majority of which is obtained under long-term contracts.
During 1993, approximately 52% of Homer City Generating
Station coal was obtained under these contracts. The
Company anticipates obtaining approximately 79% of the 1994
requirements under these contracts. The balance will be
purchased under short-term contracts and, when necessary, on
the open market.
Nuclear
During the fall of 1993, Niagara Mohawk Power
Corporation (Niagara Mohawk), the operator of the Nine Mile
Point nuclear generating unit No. 2 (NMP2), in which the
Company has an 18% interest, completed the third refueling
outage. The present core will support NMP2 operations to
1995. Enrichment services are under contract with the U.S.
Department of Energy for 100% of the services through 1995
and 70% of the services from 1996 through 1998. Fuel
fabrication services are under contract for the first seven
reloads. Approximately 55% of the uranium and conversion
requirements are under contract through 1998.
Natural Gas
As a result of FERC Order 636 (See Item 1(a)-Rates and
regulatory matters - Federal Energy Regulatory Commission (FERC)
Order 636), the Company undertook a major restructuring of its
natural gas transportation, storage, and supply contracts.
Bundled pipeline sales, gas and transportation contracts have
been eliminated thereby giving the Company greater flexibility
with respect to its supply of natural gas. The gas supply mix
now includes long-term, short-term, and spot gas purchases
transported on firm transportation contracts, as well as spot gas
purchases transported on interruptible transportation contracts.
During 1993, about 15% of the Company's natural gas supply was
purchased on firm sales contracts from CNG Transmission and
Columbia Gas Transmission. The remaining 85% was purchased from
other suppliers, approximately 25% under long-term and short-term
sales contracts and 60% on the monthly spot natural gas market to
maximize natural gas cost savings. An additional benefit of FERC
Order 636 is that the Company now has access to increased natural
gas storage space enabling it to purchase natural gas supply when
prices are favorable.
(iv) Franchises
The Company has, with minor exceptions, valid franchises
from the municipalities in which it renders service to the
public. In 1993, the Company obtained PSC authorizations for
natural gas transmission and distribution service in the towns of
Skaneateles, Stillwater, Starkey, and the town and village of
Champlain.
(v) Seasonal business
Sales of electricity are highest during the winter months
primarily due to space heating usage and fewer daylight hours.
Sales of natural gas are highest during the winter months
primarily due to space heating usage.
(vi) Working capital items
The Company has been granted, through the ratemaking
process, an allowance for working capital to operate its ongoing
electric and natural gas utility services.
(vii) Single customer - Not applicable
(viii) Backlog of orders - Not applicable
(ix) Business subject to renegotiation - Not applicable
(x) Competitive conditions (See Item 1(a)-Rates and
regulatory matters - Flexible Negotiable Rate
Tariffs; Federal Energy Regulatory Commission
(FERC) Order 636; and Restructuring and
Item 1(c)(i)-Principal business)
The utility industry is rapidly changing and facing an
increasingly competitive environment. Factors contributing to
this competitive environment are: the National Energy Policy Act
of 1992 (Energy Policy Act), which provides open access at the
wholesale level to electric transmission service, and the FERC
Order 636, which significantly affects the natural gas industry.
In addition, the Company's response to the economic pressures on
its electric industrial and other large use customers, high
purchase costs of NUGs, rising health care costs, increasing
taxes, weak economic conditions, conservation programs, and
compliance with environmental laws and regulations are all
factors that continue to place increased pressure on electric and
natural gas prices.
The Energy Policy Act, enacted in October 1992, is expected
to result in major changes to the utility industry. Certain
provisions of the Energy Policy Act amended the Public Utility
Holding Company Act of 1935 (PUHCA). These amendments encourage
greater competition in the supply market by establishing a new
category of wholesale electric generators that are exempt from
PUHCA regulation. The Energy Policy Act also enables the FERC to
order utilities to provide open access to transmission systems
for wholesale transactions, expanding opportunities for utilities
and NUGs to enter new and existing wholesale markets. These
developments serve to underscore the increasingly competitive
environment for utilities.
The Company's five-year strategic plan is designed to
address the competitive, rapidly changing utility industry. The
Company's objective is to remain competitive in its core
businesses in the face of increased competition. One of the key
strategies to meet competition is to improve customer value by
becoming a low-cost provider of energy services in the Northeast.
The Company has developed a more aggressive and accelerated
set of strategies in response to the increased challenges of
competition which are necessary to achieve the objectives
outlined in the Company's five-year strategic plan. The
following represent strategies being implemented:
- Reduce forecasted 1994 capital expenditures by one-third, or
approximately $100 million. Additional reductions will be made
in 1995 and 1996.
- Reduce operating and maintenance expenses by five percent in
1994 and again in 1995. By 1995, this will save about $40
million annually. During 1993, the Company reduced its work
force by 200 through attrition. In addition, as part of the O&M
reduction, the Company's work force was further reduced by about
600 through an early retirement opportunity program and
involuntary severance.
- Streamline the field organization to eliminate walk-in
customer service at 28 locations, and to close up to 10 electric
and natural gas operations facilities statewide.
- Place two generating units on long-term cold standby.
- Continue to reduce NUG costs. The Company's previous NUG
contract terminations and renegotiations will save customers more
than $1 billion over the terms of the contracts.
- Continue to reduce capital costs. Since 1988 the Company
has refinanced over $1.4 billion in securities, and reduced
annual interest expense by more than $55 million.
The PSC currently has a generic proceeding to study the
broad subject of flexible, competitive rates, and will establish
guidelines for the Company and other New York State utilities
during 1994. Also in late 1993, the PSC instituted a proceeding
to address issues associated with the restructuring of the
emerging competitive natural gas market. The PSC intends to
investigate services provided by New York State gas utilities
after FERC Order 636 by the 1994-1995 heating season.
Other forms of competition stem from both federal and state
action. Natural gas at the wellhead is available to be purchased
directly by end users from the producer at a delivered price
which may be less than that of the local distributor. Delivery
of such natural gas is by pipeline transportation. By law, the
Company must provide transportation service so long as it is not
an undue burden on the Company or its customers and the Company's
ability to render adequate service to its customers is not
impaired. The Company has developed, and its customers are
using, various transportation tariff services. Transportation of
natural gas in lieu of retail sales is not expected to have a
material effect on the Company's 1994 earnings.
From time to time, the price of fuel oil has allowed oil
suppliers to compete with the Company's sale of natural gas to
large natural gas customers. To meet the competition from oil,
the Company has flexible sales and transportation rates for
qualifying natural gas customers. The flexible rates provide the
Company with greater opportunity for making available rate
offerings and setting rates which more closely reflect the
competitive needs of dual-fuel customers. This capability
enhances the Company's ability to set multiple rates each month
in a manner which maximizes margins. The Company is now
utilizing and receiving benefits from the various flexible
pricing options. These flexible rates are not expected to have a
material effect on the Company's 1994 earnings and enable the
Company to minimize threats of bypass.
(xi) Research and development
Expenditures on research and development in 1993, 1992, and
1991 amounted to $18.9 million, $14.6 million, and $14.8 million,
respectively, principally for the Company's internal research
programs and for contributions to research administered by the
Electric Power Research Institute, the Empire State Electric
Energy Research Corporation, the New York Gas Group, and the New
York State Energy Research and Development Authority. These
expenditures are designed to improve existing technologies and to
develop new technologies for the production, distribution, and
conservation of energy.
(xii) Environmental matters
(See Item 3-Legal proceedings)
The Company is subject to regulation by the federal
government and by state and local governments in New York and
Pennsylvania with respect to environmental matters and is also
subject to the New York State Public Service Law requiring
environmental approval and certification of proposed major
transmission facilities.
The Company continually assesses actions that may need to be
taken to ensure compliance with changing environmental laws and
regulations. Compliance programs will increase the cost of
electric and natural gas service by requiring changes to the
Company's operations and facilities. Historically, rate recovery
has been authorized for the cost incurred for compliance with
environmental laws and regulations.
Capital additions to meet environmental requirements during
the three years ended December 31, 1993 were approximately $143.0
million and are estimated to be $76.5 million for 1994, $51.4
million for 1995, and $40 million for 1996.
Water quality
The Company is required to comply with federal and state
water quality statutes and regulations including the Clean Water
Act (Water Act). The Water Act requires that generating stations
be in compliance with federally issued National Pollutant
Discharge Elimination System Permits (NPDES Permits) or state
issued State Pollutant Discharge Elimination System Permits
(SPDES Permits), which must reflect water quality considerations
and application of the best available technology. The Company
has SPDES Permits for its six coal-fired generating stations in
New York and has applied for permit renewals for five of those
stations. Permits for these five stations have either been
renewed or are currently being negotiated with the State of New
York, in which case the existing permits for those facilities
remain in effect. The permit for the sixth station will not
expire until the fall of 1994. The Company's Homer City
Generating Station received a NPDES Permit, which expires in the
fall of 1994, from the Pennsylvania Department of Environmental
Resources (PaDER). Prior to the expiration of the two permits
which expire in the fall of 1994, renewal applications will be
submitted by the Company. Until these permits are renewed, these
stations will operate under their existing permits. SPDES
licensing renewal is currently being addressed by the New York
State Department of Environmental Conservation (NYSDEC) for NMP2.
In connection with the issuance of permits under the Water
Act, the Company has conducted studies of the effects of its coal
pile operations on groundwater quality at its Hickling, Jennison,
Milliken, and Greenidge Stations. New York State groundwater
standards are sometimes exceeded at certain locations at each of
those stations and remedial action may be required. Jennison
Station will require remedial action which is estimated to cost
up to $1 million. The remedial action, if required, at Hickling,
Milliken, and Greenidge Stations is estimated to cost $7.4
million. The Company expects to recover these expenditures in
rates, since the Company has been allowed by the PSC to recover
similar costs in rates, such as groundwater protection costs to
meet permit conditions and regulatory requirements. Remedial
action has already been performed at the Goudey Station and the
Company is currently monitoring the groundwater quality at this
station. Groundwater monitoring data for Kintigh Station does
not indicate facility induced groundwater contamination.
Groundwater studies have been initiated at the Homer City
Station.
Air quality
The Company is required to comply with federal and state air
quality statutes and regulations. All stations have the required
federal or state operating permits. Stack tests and continuous
emission monitoring indicate that the stations are generally in
compliance with permit emission limitations, although occasional
opacity exceedances occur. Efforts are underway to identify and
eliminate the causes of opacity exceedances.
The Clean Air Act Amendments of 1990 (1990 Amendments) will
result in significant expenditures of approximately $178 million,
on a present value basis, over a 25-year period, for all capital
and operating and maintenance expenses related to the reduction
of sulfur dioxide and nitrogen oxides at several of the Company's
coal-fired generating stations, of which $51 million has been
incurred as of December 31, 1993. The Company's current estimate
is a significant reduction from its prior estimate, primarily due
to the postponement of the construction of a flue gas
desulfurization (FGD) system at its Homer City Generating
Station. The Company plans to re-evaluate the need to construct
an FGD system at the Homer City Generating Station in 1995, since
its present strategy to bank Phase I emissions allowances for use
during Phase II, as discussed below, will allow the Company to
meet Phase II allowance requirements through the year 2005. The
cost to comply with the sulfur dioxide and nitrogen oxide
limitations includes the construction of an innovative FGD system
and a nitrogen oxide reduction system expected to be completed in
1995 at the Company's Milliken Generating Station. The Company
estimates that approximately a 1% electric rate increase will be
required for the cost of reducing sulfur dioxide and nitrogen
oxide emissions in both Phase I (begins January 1, 1995) and
Phase II (begins January 1, 2000). As a result of the 1990
Amendments, the Company plans to reduce its annual sulfur dioxide
emissions by an amount that will allow the Company to meet the
sulfur dioxide levels established for the Company, which is
approximately a 49% reduction from approximately 138,000 tons in
1989 to 71,000 tons by the year 2000.
The cost of controlling toxic emissions under the 1990
Amendments, if required, cannot be estimated at this time.
Regulations may be adopted at the state level which would limit
toxic emissions even further, at an additional cost to the
Company. The Company anticipates that the costs incurred to
comply with the 1990 Amendments will be recoverable through rates
based on previous rate recovery of required environmental costs.
The 1990 Amendments require the U.S. Environmental
Protection Agency (EPA) to allocate annual emissions allowances
to each of the Company's coal-fired generating stations based on
statutory emissions limits. An emissions allowance represents an
authorization to emit, during or after a specified calendar year,
one ton of sulfur dioxide. During Phase I, the Company estimates
that it will have allowances in excess of the affected coal-fired
generating stations' actual emissions. The Company's present
strategy is to bank these allowances for use in later years. By
using a banking strategy, it is estimated that Phase II allowance
requirements will be met through the year 2005 by utilizing the
allowances banked during Phase I, which includes the extension
reserve allowances discussed below, together with the Company's
Phase II annual emissions allowances. This strategy could be
modified should market or business conditions change. In
addition to the annual emissions allowances allocated to the
Company by the EPA, the Company will receive a portion of the
extension reserve allowances issued by the EPA to utilities
electing to build scrubbers, as a result of the pooling agreement
that it entered into with other utilities who were also eligible
to receive some of these extension reserve allowances.
Certain other environmental regulations limit the amount of
particulate matter which may be emitted into the environment.
The Company and Pennsylvania Electric Company may find it
necessary either to upgrade or install additional equipment at
the Homer City Generating Station in order to consistently meet
the particulate emission requirements.
Waste disposal
The Company has received or applied for SPDES Permits, Solid
Waste Disposal Facilities Permits, and applicable local permits
for its active ash disposal sites for its New York generating
stations. Groundwater standards have been exceeded in areas
close to portions of the Milliken and Weber ash disposal sites.
Corrective actions have been taken and studies are continuing to
monitor the effectiveness of the corrective actions.
The Company has received NPDES permits, a Solid Waste
Disposal Permit, and applicable local permits for its active ash
disposal site for the Homer City Generating Station and for the
active refuse disposal site for the Homer City Coal Cleaning
Plant. In September 1993, the Company completed its study of
costs to comply with the new Pennsylvania residual waste
regulations governing solid waste disposal over the next 30
years.
As a result of existing and new solid waste disposal
legislation and regulations in Pennsylvania, the Company will
incur approximately $24 million, on a present value basis, of
additional costs over the next 30 years, beginning in 1994, at
the Homer City Generating Station. These costs will be incurred
to install new equipment, modify or replace existing equipment,
and improve the design of a proposed expansion of disposal
facilities. The Company expects to recover these expenditures in
rates, since the Company has been allowed by the PSC to recover
similar costs in rates, such as groundwater protection costs to
meet permit conditions and regulatory requirements.
Due to existing and proposed legislation and regulations,
and legal proceedings commenced by governmental bodies and
others, the Company may also incur costs from the past disposal
of hazardous substances produced during the Company's operations
or those of its predecessors. The Company has been notified by
the EPA and the NYSDEC that it is among the potentially
responsible parties (PRPs) who may be liable to pay for costs
incurred to remediate certain hazardous substances at seven waste
sites, not including the Company's inactive gas manufacturing
sites, which are discussed below. With respect to the seven
sites, five sites are included in the New York State Registry of
Inactive Hazardous Waste Sites (New York State Registry).
Any liability may be joint and several for certain of these
sites. The ultimate cost to remediate these sites will be
dependent on such factors as the remedial action plan selected,
the extent of site contamination, and the portion attributed to
the Company. At December 31, 1993, the Company recorded a
liability in the Consolidated Balance Sheets related to four of
these seven waste sites of $1.8 million. The Company has
notified the NYSDEC that it believes it has no responsibility at
two sites and has already incurred expenditures related to the
remediation at the remaining site. A deferred asset has also
been recorded in the amount of $2.6 million, of which $.8 million
relates to costs that have already been incurred. The Company
believes it will recover these costs, since the PSC has allowed
other utilities to recover these types of remediation costs and
has allowed the Company to recover similar costs in rates, such
as investigation and cleanup costs relating to inactive gas
manufacturing sites. This $1.8 million estimate was derived by
multiplying the total estimated cost to clean up a particular
site by the related Company contribution factor. Estimates of
the total cleanup costs were determined by using information
related to a particular site, such as investigations performed to
date at a site or from the data released by a regulatory agency.
In addition, this estimate was based upon currently available
facts, existing technology, and presently enacted laws and
regulations. The contribution factor is calculated using either
the Company's percentage share of the total PRPs named, which
assumes all PRPs will contribute equally, or the Company's
estimated percentage share of the total hazardous wastes
disposed of at a particular site, or by using a 1% contribution
factor for those sites at which it believes that it has
contributed a minimal amount of hazardous wastes. The Company
has notified its former and current insurance carriers that it
seeks to recover from them certain of these cleanup costs.
However, the Company is unable to predict the amount of insurance
recoveries, if any, that it may obtain.
A number of the Company's inactive gas manufacturing sites
have been listed in the New York State Registry. The Company has
filed petitions to delist the majority of the sites. The
Company's program to investigate and initiate remediation at its
38 known inactive gas manufacturing sites has been extended
through the year 2000. Expenditures over this time period are
estimated to be $25 million. This estimate was determined by
using the Company's experience and knowledge related to these
sites as a result of the investigation and remediation that the
Company has performed to date. It is based upon currently
available facts, existing technology, and presently enacted laws
and regulations. This liability, to investigate and initiate
remediation, as necessary, at the known inactive gas
manufacturing sites is reflected in the Company's Consolidated
Balance Sheets at December 31, 1993 and 1992. The Company also
has recorded a corresponding deferred asset, since it expects to
recover such expenditures in rates, as the Company has previously
been allowed by the PSC to recover such costs in rates. The
Company has notified its former and current insurance carriers
that it seeks to recover from them certain of these cleanup
costs. However, the Company is unable to predict the amount of
insurance recoveries, if any, that it may obtain.
A low level radioactive waste management and contingency
plan that has been developed for NMP2 provides assurance that
NMP2 is properly prepared to handle interim storage of low level
radioactive waste until 1998.
Niagara Mohawk has contracted with the U.S. Department of
Energy (DOE) for disposal of high level radioactive waste (spent
fuel) from NMP2. The Company is reimbursing Niagara Mohawk for
its 18% share of the cost under the contract (currently
approximately $1 per megawatt hour of net generation). The DOE's
schedule for start of operations of their high level radioactive
waste repository has slipped from 2003 to no sooner than 2010.
The Company has been advised by Niagara Mohawk that the NMP2
Spent Fuel Storage Pool has a capacity for spent fuel that is
adequate until 2014. If further DOE schedule slippage should
occur, the recent development of pre-licensed dry storage
facilities for use at any nuclear power plant extends the on-site
storage capability for spent fuel at NMP2 beyond 2014.
(xiii) Number of employees
The Company had 4,746 employees as of December 31, 1993 (See
Item 1(a)-Restructuring)
(d) Financial information about foreign and domestic operations
and export sales - Not applicable
Item 2. Properties
The Company's electric system includes coal-fired, nuclear,
hydroelectric, and internal combustion generating stations,
substations, and transmission and distribution lines, all of
which are located in the State of New York, except for the Homer
City Generating Station and related facilities which are located
in the Commonwealth of Pennsylvania. Generating facilities are:
Name and location of station Generating
capability (kw)
Coal-fired
Goudey * (Binghamton, N.Y.) 127,000
Greenidge * (Dresden, N.Y.) 162,000
Hickling (East Corning, N.Y.) 86,000
Jennison (Bainbridge, N.Y.) 72,000
Milliken (Lansing, N.Y.) 318,000
Kintigh (Somerset, N.Y.) 675,000
Homer City (Homer City, Pa.) 954,000**
---------
Total coal-fired 2,394,000
Nuclear
NMP2 (Oswego, N.Y.) 189,000***
Hydroelectric (Various - 9 locations) 66,500
Internal combustion (Various - 2 locations) 7,200
---------
Total - all stations 2,656,700
=========
* In the spring and summer of 1994 the Company plans to place
one unit at both Goudey and Greenidge on long-term cold
standby. These units have a combined capability of 97
megawatts.
** Company's 50% share of the generating capability.
***Company's 18% share of the generating capability.
The Company owns 446 substations having an aggregate
transformer capacity of 12,634,177 Kilovolt-amperes. The
transmission system consists of 4,774 circuit miles of line and
the distribution system of 33,410 pole miles of overhead lines
and 1,790 miles of underground lines.
The Company's natural gas system consists of the
distribution of natural gas through 452 miles of transmission
pipelines (3-inch equivalent) and 5,360 miles of distribution
pipelines (3-inch equivalent).
Somerset Railroad Corporation (SRC), a wholly-owned
subsidiary, owns a rail line consisting of 15 1/2 miles of track
and related property rights in Lockport, Newfane, and Somerset,
New York which is used to transport coal and other materials to
the Kintigh Generating Station.
The Company's first mortgage bond indenture constitutes a
direct first mortgage lien on substantially all of the Company's
properties. Substantially all of the properties of SRC, other
than rolling stock, are subject to a lien of a mortgage and
security agreement.
Item 3. Legal proceedings
(See Item 1(a)-Rates and regulatory matters, 1(c)(i)-Principal
business, (x)-Competitive conditions, and (xii)-Environmental
matters)
The Company is unable to predict the ultimate disposition of
the matters referred to below in (c), (d), (e), (g), (h), (i),
and (j). There is no clear precedent with the PSC for rate
recovery of the types of costs referred to in these matters.
However, since the PSC has previously allowed the Company to
recover similar costs in rates, such as investigation and clean-
up costs relating to coal tar sites, the Company expects to
recover in rates any remediation costs that it may incur.
Therefore, the Company believes that the ultimate disposition of
the matters referred to below in (c), (d), (e), (g), (h), (i),
and (j) will not have a material adverse effect on its results of
operations or financial position.
(a) On January 27, January 31, and February 15, 1984, and on
June 29, 1987, numerous individual plaintiffs instituted lawsuits
in the Supreme Court of the State of New York (Broome County) for
personal injuries allegedly arising out of a transformer fire at
the State Office Building in Binghamton, New York, in February
1981. Multiple defendants, including the Company, are named in
the actions which seek an aggregate of $329 million in
compensatory and exemplary damages. Because the transformers
involved were not owned, installed, or serviced by the Company,
the Company believes that these claims against the Company are
without merit.
(b) On January 15 and January 30, 1985, numerous individual
plaintiffs instituted two lawsuits against the Company in the
Supreme Court of the State of New York (Broome County) seeking a
total of $70 million in compensatory damages, plus punitive
damages in an unstated amount. These actions arise out of a
spill of PCB-contaminated oil on the Company's property on
February 1, 1982. One of the lawsuits alleges mental anguish as
the basis for recovery. The other lawsuit does not specify the
nature of the damages claimed, except for an alleged decrease in
the value of one residential property in the vicinity of the
spill and deprivation of plaintiffs' right to quiet enjoyment of
their property. Because the spill was contained on the Company's
property and was quickly removed, the Company believes that these
claims are without merit. Plaintiffs' counsel terminated their
representation of the plaintiffs in these actions in 1988. The
Company has not been notified of a substitution of attorneys for
any of the plaintiffs and there has been no activity in these
lawsuits since February 1988.
(c) By letter dated February 29, 1988, the NYSDEC notified the
Company that it has been identified as a potentially responsible
party for investigation and remediation of the disposal of
hazardous wastes at the Lockport City Landfill Site (Lockport
Site) in Lockport, New York. The Lockport Site is listed on the
New York State Registry. Four other potentially responsible
parties were identified in the NYSDEC letter. The Company has
been offered an opportunity to conduct remediation or finance
remediation costs at the Lockport Site, failing which the NYSDEC
might remediate the Lockport Site itself and commence an action
to recover its costs and damages. The Company believes that
remediation costs at the Lockport Site might rise to $6 million.
By letter dated May 2, 1988, the Company notified the NYSDEC that
it declined to finance remediation costs because it believes that
the NYSDEC had not demonstrated that a significant threat to
public health or the environment exists at the Lockport Site.
(d) By letter dated December 10, 1990, the NYSDEC notified the
Company that it had been identified as a potentially responsible
party for investigation and remediation of the disposal of
hazardous wastes at the Schreck's scrapyard site (Schreck's Site)
in the City of North Tonawanda, New York. The Schreck's Site is
listed on the New York State Registry. Seven other potentially
responsible parties were identified in the NYSDEC letter. On
February 3, 1992, the NYSDEC again notified the Company that it
had been identified as a potentially responsible party for
investigation and remediation costs at the Schreck's Site, this
time listing eight other potentially responsible parties. The
Company has been offered an opportunity to conduct remediation or
finance remediation costs at the Schreck's Site, failing which
the NYSDEC might remediate the Schreck's Site itself and commence
an action to recover its costs and damages. The NYSDEC currently
estimates that remediation costs at the Schreck's Site will be
$4.5 million. By letter dated April 1, 1992, the Company
notified the NYSDEC that it believed it had no responsibility for
the alleged contamination at the Schreck's Site, and it declined
to conduct remediation or finance remediation costs.
(e) By letter dated June 7, 1991, the NYSDEC notified the
Company that it had been identified as a potentially responsible
party at the Pfohl Brothers Landfill inactive hazardous waste
disposal site (Pfohl Site) in Cheektowaga, New York. The Pfohl
Site is listed on the New York State Registry. The NYSDEC
offered the Company an opportunity to enter into negotiations
with it to undertake the investigation and remediation of the
Pfohl Site. The NYSDEC informed the Company that if it declined
such negotiations, the NYSDEC would perform the necessary work at
the Pfohl Site using the Hazardous Waste Remedial Fund and would
seek recovery of its expenses from the Company. On July 3, 1991,
the Company responded to the NYSDEC by declining to negotiate to
undertake work at the Pfohl Site and noted that the NYSDEC had
not shown any significant responsibility on the part of the
Company for the situation at the Pfohl Site. The Company
believes that remediation costs at the Pfohl Site will be $35
million to $55 million. By letter dated April 2, 1992, the
NYSDEC again notified the Company that it had been identified as
a potentially responsible party for the Pfohl Site and offered
the Company an opportunity to conduct or finance the on-site
remedial design and action. This notice letter was also sent to
19 other potentially responsible parties. Ten of these other
named potentially responsible parties have agreed to perform the
remedial work required by the NYSDEC. By letter dated June 1,
1992, the Company notified the NYSDEC that it declined to perform
such remedial work because it believed that it was not a
significant contributor to the Pfohl Site.
(f) By complaint dated October 31, 1991, General Motors
Corporation (GM) commenced a lawsuit against the Company in the
U. S. District Court for the Western District of New York. GM
alleges, among other claims, that the Company violated various
federal antitrust laws in connection with billings for electric
service provided by the Company at GM's Harrison Radiator Plant
at Lockport, New York. GM's claims are for damages incurred and
to be incurred. The Company estimates that GM is claiming
approximately $8 million, after trebling. The Company believes
that it has not violated the federal antitrust laws and that this
lawsuit is without merit.
On October 5, 1993, the Magistrate to whom the case had been
referred issued a decision recommending that GM's complaint be
dismissed. The District Judge responsible for the case, after
reviewing GM's exceptions to the decision and the Company's
reply, will decide whether to adopt the Magistrate's recommended
decision.
(g) By letter dated January 21, 1992, the NYSDEC notified the
Company that it had been identified as a potentially responsible
party at the Peter Cooper Corporation's Landfill Site (Peter
Cooper Site) in the village of Gowanda, New York. Three other
potentially responsible parties were identified in the NYSDEC
letter. The NYSDEC letter also notified the Company that state
surface water and groundwater standards had been exceeded at the
Peter Cooper Site and offered the Company an opportunity to
conduct or finance a remedial program. NYSDEC indicated that if
the Company did not agree to enter into a consent order it would
perform the necessary work itself or seek a court order requiring
the Company to conduct the work. The Company believes that
remediation costs at the Peter Cooper Site might rise to $16
million. By letter dated May 12, 1992, the Company notified the
NYSDEC that it believed it had no responsibility for the alleged
contamination at the Peter Cooper Site, and it declined to
conduct remediation or finance remediation costs.
(h) By letter dated April 20, 1992, the EPA notified the Company
that it had been identified as a potentially responsible party at
the Bern Metals Removal Site (Bern Metals Site) in Buffalo, New
York. Four other potentially responsible parties have been
identified by the EPA. The EPA has taken response actions at the
Bern Metals Site, including investigation, excavation, and
removal of drums and contaminated soil, and implementation of
measures to prevent surface water run-off. The EPA has demanded
that the Company reimburse the EPA Hazardous Substances Superfund
$2 million in response costs incurred to date by the EPA, with
interest accruing from the date of the demand. Future response
or remedial costs which the EPA may incur at the Bern Metals Site
are not covered by the EPA demand and the EPA has reserved its
rights relating to any such costs.
In addition to the foregoing, the NYSDEC, by letter dated
July 21, 1992, notified the Company that it had been identified
as a potentially responsible party at the Bern Metals Site, which
the NYSDEC defined to include an adjacent property known as the
Universal Iron & Metal Site (Bern Metals/Universal Iron Site).
The Bern Metals/Universal Iron Site is listed on the New York
State Registry. The NYSDEC has also identified eight other
potentially responsible parties for the Bern Metals/Universal
Iron Site. The NYSDEC has requested that the Company, and the
eight other identified potentially responsible parties, enter
into negotiations in which the Company and the other identified
potentially responsible parties would agree to finance or conduct
a Remedial Investigation and Feasibility Study (RI/FS) designed
to determine what further remediation or removal actions may be
appropriate for the Bern Metals/Universal Iron Site. The NYSDEC
has provided no estimate of the cost of the response action it
proposes. By letter dated December 3, 1992, the Company declined
to negotiate with NYSDEC to finance or conduct an RI/FS for the
Bern Metals/Universal Iron Site, because the Company believed it
was only a very small contributor to the Bern Metals/Universal
Iron Site. In addition, the Company believes that it does not
have any connection with the Universal Iron & Metal Site.
(i) By letter dated April 20, 1992, the EPA notified the Company
that the EPA had reason to believe that the Company was a
potentially responsible party for the Clinton-Bender Removal Site
(Clinton-Bender Site) in Buffalo, New York. Four other
potentially responsible parties have been identified by the EPA.
Nine private residential lots and one commercial property at the
Clinton-Bender Site are contaminated with lead, allegedly due to
run-off from the adjacent Bern Metals Site. The EPA has
requested that the Company perform the necessary removal work at
the Clinton-Bender Site and the Company is doing so in
conjunction with the four other identified potentially
responsible parties. The total cost of the removal actions to be
performed at the Clinton-Bender Site is estimated to be
$3.1 million.
On November 3, 1993, the Company was served with a summons
and complaint filed on behalf of certain of the homeowners at the
Clinton-Bender Site. Seven other defendants were named in the
complaint, which was filed in the New York State Supreme Court,
Erie County. The action has since been removed to the U.S.
District Court for the Western District of New York (District
Court). In their complaint, plaintiffs make general allegations
that the defendants violated federal environmental laws without
alleging facts in support of these allegations. Plaintiffs also
allege personal injury, property damage, and fear of cancer which
they claim were caused by the presence of hazardous substances on
their property, allegedly resulting from the disposal of such
substances by the defendants at the Bern Metals Site. Any
liability incurred as a result of these claims may be joint and
several. The plaintiffs ask for $30 million in direct damages
from all defendants, as well as treble damages (for unspecified
reasons) from all defendants, and an additional $10 million in
punitive damages from each defendant. The Company and some of
the other defendants in this matter have made a motion to the
District Court for dismissal of all claims based upon the Clean
Air Act, the Clean Water Act, and the Comprehensive Environmental
Response, Compensation, and Liability Act, which are the only
claims based upon federal causes of action. The Company believes
that its position in this action is meritorious, and it will
defend this case vigorously.
(j) By letter dated February 12, 1993, NYSDEC notified the
Company that it had been identified as a potentially responsible
party for remediation of hazardous wastes at the Booth Oil Site
(Booth Oil Site) in North Tonawanda, New York. The Booth Oil
Site is listed on the New York State Registry. Twelve other
potentially responsible parties were identified in the NYSDEC
letter. Booth Oil Company is a waste oil re-refiner and
recycler. The Company had sent waste oils to Booth Oil Company
for disposal as had numerous other companies in the Buffalo area.
According to NYSDEC, the Booth Oil Site is contaminated with
PCBs, lead, and other substances. NYSDEC has requested that the
Company and the other identified potentially responsible parties
conduct remediation at the Booth Oil Site pursuant to an Order on
Consent to be negotiated with NYSDEC. NYSDEC has estimated that
the present value of costs for on-site treatment alternatives
range from $12 million to $24 million.
Item 4. Submission of matters to a vote of security holders -
Not applicable.
* * * * * * * * * *
Executive officers of the Registrant
Positions, offices and
business experience -
Name Age January 1989 to date
James A. Carrigg 60 Chairman, President and Chief Execu-
tive Officer, January 1991 to date;
Chairman and Chief Executive Officer,
to January 1991.
Richard P. Fagan 53 Senior Vice President-Management
Services Business Unit, April 1990 to
date; Senior Vice President-
Administration, March 1989 to April
1990; Senior Vice President to March
1989.
Executive officers of the Registrant (Cont'd)
Positions, offices and
business experience -
Name Age January 1989 to date
Russell Fleming, Jr. 55 Senior Vice President-Gas Business
Unit, October 1990 to date; Partner in
Putnam, Hayes and Bartlett (economic
and management consultants), New York,
New York May 1989 to September 1990;
Partner in Theodore Barry & Associates
(management consultants), New York, NY
to May 1989.
Jack H. Roskoz 55 Senior Vice President-Electric Business
Unit, April 1990 to date; Senior Vice
President, March 1989 to April 1990;
Senior Vice President-Administration to
March 1989.
John J. Bodkin 48 Vice President-Electric Transmission
and Distribution, January 1991 to date;
Manager-Power Supply, to January 1991.
Gerald E. Putman 43 Vice President-Fuel Supply and Opera-
tion Services, May 1993 to date; Vice-
President-East Region Electric, Septem-
ber 1992 to May 1993; Executive
Assistant to the Chairman, President
and Chief Executive Officer, January
1991 to September 1992; District
Manager, Auburn, NY to January 1991.
Sherwood J. Rafferty 46 Vice President and Treasurer, September
1990 to date; Treasurer, to September
1990.
Vincent W. Rider 62 Vice President-Generation.
Everett A. Robinson 50 Vice President and Controller,
September 1990 to date; Controller,
to September 1990.
Irene M. Stillings 54 Vice President-Electric Marketing,
January 1991 to date; Assistant Vice
President-Consumer Services and
Communications, February 1989 to
January 1991; Assistant Vice President-
Consumer Affairs, to February 1989.
Ralph R. Tedesco 40 Vice President-Strategic Growth
Business Unit, February 1994 to date;
Executive Assistant to the Chairman,
President and Chief Executive Officer,
September 1992 to February 1994;
Manager, Corporate Performance June
1991 to September 1992; Manager,
Research and Development to June 1991.
Executive officers of the Registrant (Cont'd)
Positions, offices and
business experience -
Name Age January 1989 to date
Denis E. Wickham 45 Vice President-Electric Resource
Planning, January 1991 to date;
Assistant to Senior Vice President, to
January 1991.
The Company has entered into an agreement with James A.
Carrigg which provides for his employment as Chairman, President
and Chief Executive Officer of the Company for a term ending on
December 31, 1996, with automatic one-year extensions unless
either he or the Company gives notice that the agreement is not
to be extended.
Each officer holds office for the term for which he or she
is elected or appointed, and until his or her successor shall be
elected and shall qualify. The term of office for each officer
extends to and expires at the meeting of the Board of Directors
following the next annual meeting of stockholders.
PART II
Item 5. Market for Registrant's common stock and related
stockholder matters
See Note 13 to the Consolidated Financial Statements on page
73.
Item 6. Selected Financial Data
(Thousands-except per share data) 1993 1992 1991 1990 1989
- ------------------------------------------------------------------------------------------------------
Operating revenues $1,800,149 $1,691,689 $1,555,815 $1,496,780 $1,427,745
Net Income $166,028* $183,968 $168,643 $158,013 $157,779**
Earnings per share $2.08* $2.40 $2.36 $2.48 $2.53**
Dividends paid per share $2.18 $2.14 $2.10 $2.06 $2.02
Average shares outstanding 69,990 67,972 62,906 58,678 57,138
Book value per share of common stock(year end) $22.89 $22.85 $22.16 $21.85 $21.29
Interest charges $145,450 $155,388 $163,526 $173,390 $180,068
AFDC and non-cash return $8,003 $6,482 $7,541 $5,776 $6,387
Depreciation and amortization $164,568 $158,977 $152,380 $147,659 $148,375
Other taxes $204,962 $200,941 $178,185 $158,770 $146,605
Construction expenditures $245,029 $245,618 $245,883 $210,725 $192,022
Total assets $5,276,016 $5,077,916 $4,924,836 $4,737,431 $4,670,283
Long-term obligations,capital leases and
redeemable preferred stock $1,755,629 $1,883,927 $1,897,465 $1,766,457 $1,799,800
*Net income and earnings per share for 1993 include the effects of restructuring expenses, which
decreased net income by $17.2 million, and decreased earnings per share by 25 cents.
**Net income and earnings per share for 1989 include the effects of the adjustment recorded in December
1989 to the 1987 Nine Mile Point nuclear generating unit No. 2 write-off. Excluding that adjustment,
net income and earnings per share for 1989 were $151,998 and $2.43, respectively.
Principal Sources of Electric and Natural Gas Revenues
ELECTRIC 1993 % of Total 1992 % of Total 1991 % of Total
-------------------------------------------------------------------------
Kwh Sales (millions):
Residential 5,423 28.0 % 5,472 28.4 % 5,297 29.1
Commercial 3,298 17.1 3,283 17.0 3,285 18.1
Industrial 2,950 15.3 3,082 16.0 3,068 16.9
Other 1,417 7.3 1,457 7.5 1,457 8.0
----------- ------- ----------- ------- ----------- -------
Total retail 13,088 67.7 13,294 68.9 13,107 72.1
Other electric utilities 6,233 32.3 6,003 31.1 5,066 27.9
----------- ------- ----------- ------- ----------- -------
Total 19,321 100.0 % 19,297 100.0 % 18,173 100.0 %
=========== ======= =========== ======= =========== =======
Operating Revenues (thousands):
Residential $635,155 41.6 % $601,042 41.4 % $553,056 40.4 %
Commercial 333,674 21.8 314,272 21.7 293,197 21.5
Industrial 228,215 14.9 225,832 15.5 207,933 15.2
Other 138,320 9.1 133,819 9.2 124,575 9.1
----------- ------- ----------- ------- ----------- -------
Total retail 1,335,364 87.4 1,274,965 87.8 1,178,761 86.2
Other electric utilities 147,175 9.6 143,413 9.9 131,412 9.6
Unbilled revenue recognition-net 2,257 0.2 (427) - 35,333 2.6
Other operating revenues 42,566 2.8 33,574 2.3 22,430 1.6
----------- ------- ----------- ------- ----------- -------
Total operating revenues $1,527,362 100.0 % $1,451,525 100.0 % $1,367,936 100.0 %
=========== ======= =========== ======= =========== =======
Natural Gas
Dekatherm(thousands)
Residential 25,080 43.2 % 24,913 44.2 % 18,115 42.7 %
Commercial 10,640 18.3 10,796 19.1 8,054 19.0
Industrial 1,820 3.2 1,689 3.0 1,788 4.2
Other 1,805 3.1 1,959 3.5 1,917 4.5
----------- ------- ----------- ------- ----------- -------
Total retail sales 39,345 67.8 39,357 69.8 % 29,874 70.4
Transportation of customer-owned
natural gas 18,701 32.2 17,009 30.2 12,530 29.6
----------- ------- ----------- ------- ----------- -------
Total natural gas deliveries 58,046 100.0 % 56,366 100.0 % 42,404 100.0 %
=========== ======= =========== ======= =========== =======
Operating Revenues(thousands):
Residential $170,734 62.6 % 152,325 63.4 % $111,106 59.1 %
Commercial 66,648 24.5 59,939 25.0 43,969 23.4
Industrial 9,602 3.5 8,092 3.4 8,640 4.6
Other 10,943 4.0 10,762 4.5 10,243 5.5
----------- ------- ----------- ------- ----------- -------
Sub-total 257,927 94.6 231,118 96.3 173,958 92.6
Transportation of customer-owned
natural gas 12,091 4.4 11,639 4.8 9,571 5.1
Unbilled revenue recognition-net 2,686 1.0 (3,626) (1.5) 3,770 2.0
Other natural gas revenue 83 0.0 1,033 .4 580 .3
----------- ------- ----------- ------- ----------- -------
Total operating revenues $272,787 100.0 % $240,164 100.0 % $187,879 100.0 %
=========== ======= =========== ======= =========== =======
Item 7. Management's discussion and analysis of financial
condition and results of operations
Results of Operations
1993 1992
over over
1992 1991
1993 1992 1991 Change Change
(Thousands, except Per Share Amounts)
Operating revenues $1,800,149 $1,691,689 $1,555,815 6% 9%
Earnings available for
common stock $145,390 $162,973 $148,313 (11%) 10%
Average shares outstanding 69,990 67,972 62,906 3% 8%
Earnings per share $2.08 $2.40 $2.36 (13%) 2%
Dividends per share $2.18 $2.14 $2.10 2% 2%
In 1993, operating revenues increased $108 million, or 6%,
compared to 1992. This increase is primarily because of increases
in electric and natural gas rates that became effective in August
1992 and September 1993, which totaled $61 million, and the
amounts billed to customers for higher costs of non-utility
generation (NUG) power and natural gas totaling $51 million.
In 1992, operating revenues rose $136 million, or 9%,
compared to 1991. The amounts billed to customers for higher
costs of NUG power of $41 million, and increases in electric and
natural gas rates effective in February 1991 and August 1992,
which totaled $40 million, were the primary reasons for this
increase. In addition, higher electric and natural gas retail
sales due to an increase in retail customers, colder weather, and
the April 1991 acquisition of Columbia Gas of New York, Inc.
(CNY) helped boost operating revenues by $51 million in 1992.
Earnings per share decreased 32 cents, or 13%, in 1993
compared to 1992, while earnings per share increased 4 cents, or
2%, in 1992 compared to 1991. Both 1993 and 1992 had non-
recurring items that lowered earnings per share. Earnings in
1993 were reduced by 25 cents per share as a result of a
corporate restructuring that will reorganize the way the Company
delivers services to its electric and natural gas customers
beginning in March 1994. This restructuring resulted in a work
force reduction throughout the organization of approximately 600,
the elimination of customer walk-in services at 28 satellite
locations, and the closing of up to 10 electric and natural gas
operations facilities statewide. This is one of several actions
the Company has taken to reduce future costs, enhance
efficiencies in service to its customers, and be competitive in
the rapidly changing utility industry (See Competitive
Conditions). A six-month electric rate moratorium, which began
in February 1992, limited 1992 earnings per share by 24 cents.
Excluding the effect of these non-recurring items, earnings per
share decreased 31 cents in 1993 compared to 1992, and increased
28 cents in 1992 compared to 1991.
The 31 cent 1993 decrease in earnings per share was
primarily due to lower electric retail sales prior to the
effective date of the Company's modified revenue decoupling
mechanism (See Regulatory Matters) and lower than anticipated
natural gas sales, both resulting from the sluggish economy in
the Company's service territory. Also, earnings per share
decreased due to changes in the Company's allowed return on
equity from 11.7% effective through July 1992, to 11.2% effective
through July 1993, and then to 10.8% beginning in August 1993.
In 1992, earnings per share were favorably affected by the
growth in electric and natural gas retail sales primarily due to
an increase in retail customers, colder weather, and the April
1991 acquisition of CNY. The Company's efforts to control costs
also contributed to the increase in 1992 earnings per share.
Average shares outstanding were 70 million in 1993, 68
million in 1992, and 63 million in 1991. Average shares
outstanding increased 3% in 1993 compared to 1992 due to the
issuance of 1.2 million shares of common stock through the
Dividend Reinvestment and Stock Purchase Plan (DRP). In 1992,
average shares outstanding increased 8% because of a public
offering of 5 million shares of common stock in March 1992, and
the issuance of 1 million shares of common stock through the DRP.
Interest Expense
Interest expense (before the reduction for allowance for
borrowed funds used during construction) decreased by $10
million, or 6%, in 1993 and $8 million, or 5%, in 1992. Interest
on long-term debt decreased in 1993 and 1992 mainly due to the
refinancing of certain high-coupon long-term debt at lower
interest rates, and lower interest rates on the Company's
variable rate debt. In 1993 and 1992 interest expense also
decreased due to a reduction in the interest rate on the
commercial paper borrowings (See Financing Activities).
Operating Results by Business Unit
1993 1992
over over
1992 1991
Electric 1993 1992 1991 Change Change
(Thousands)
Retail sales-kilowatt-
hours(kwh) 13,088,175 13,294,466 13,107,115 (2%) 1%
Operating revenues $1,527,362 $1,451,525 $1,367,936 5% 6%
Operating expenses $1,250,000 $1,146,619 $1,056,969 9% 8%
Electric retail sales decreased 2% in 1993 compared to 1992
as a result of the sluggish economy in the Company's service
territory and in spite of a 1% increase of customers. In 1992,
electric retail sales increased 1% compared to 1991 mainly due to
colder but more normal weather and an increase in customers.
The primary cause of the $76 million, or 5%, increase in
electric operating revenues in 1993 was the increase in rates
effective August 1992 and September 1993, which accounted for
$53 million of the increase. Also contributing to this increase
were higher costs of NUG power of $28 million, which were billed
to customers. Electric operating revenues increased $84 million,
or 6%, in 1992 compared to 1991. This increase reflects the
increases in electric rates that became effective February 1991
and August 1992 and that increased revenues by $35 million. The
revenue increase reflects higher NUG costs of $41 million and an
increase in certain New York State gross receipts taxes of $12
million, both of which were billed to customers. Also, increased
electric retail sales, due to colder weather and an increase in
customers, boosted revenues by $9 million.
Electric operating expenses increased $103 million, or 9%,
in 1993 compared to 1992, and $90 million, or 8%, in 1992
compared to 1991. In 1993, electricity purchased from NUGs
increased $67 million. Other operating expenses increased
primarily due to an increase in postretirement benefit costs
other than pensions of $7 million. In addition, electric
operating expenses increased $21 million due to the corporate
restructuring. These increases were partially offset by a
decrease of $17 million in fuel used in electric generation, the
result of lower generation and a decrease in the price of coal,
and a decrease of $12 million in federal income taxes, the
result of lower pre-tax book income.
In 1992, electricity purchased increased primarily because
of the amounts billed to customers for higher NUG costs, which
totaled $41 million. Other operating expenses increased
primarily because of higher demand-side management (DSM) program
costs of $6 million. Federal income taxes increased $4 million
resulting from higher pre-tax book income. Other taxes increased
primarily because of an increase in certain New York State gross
receipts taxes and property taxes of $16 million. These
increases were partially offset by a decrease of $12 million in
fuel used in electric generation, the result of lower generation
and a decrease in the price of coal, and a decrease in
maintenance expense of $7 million.
1993 1992
over over
1992 1991
Natural Gas 1993 1992 1991 Change Change
(Thousands)
Deliveries
-dekatherms(dth) 58,046 56,366 42,404 3% 33%
Retail sales-(dth) 39,345 39,357 29,874 - 32%
Operating revenues $272,787 $240,164 $187,879 14% 28%
Operating expenses $249,493 $221,307 $177,751 13% 25%
Natural gas deliveries increased 3% in 1993 compared to 1992
while natural gas retail sales were flat. In 1992, natural gas
deliveries and retail sales increased 33% and 32%, respectively,
compared to 1991. The increase in deliveries in 1993 reflects an
increase in the number of transportation customers. The 1992
increases in deliveries, as well as retail sales, are largely
because of the April 1991 acquisition of CNY. Excluding CNY,
natural gas retail sales increased 8% in 1992, primarily because
of the colder but more normal weather.
Natural gas operating revenues rose $33 million, or 14%, in
1993 compared to 1992, and $52 million, or 28%, in 1992 compared
to 1991. In 1993, the increase was primarily due to higher costs
of natural gas of $23 million, which were billed to customers,
and the increases in rates in August 1992 and September 1993,
which totalled $8 million. The 1992 revenue increases are
principally the result of the acquisition of CNY, which added $35
million, and the increases in rates effective February 1991 and
August 1992 amounting to $4 million. Also, the recovery of an
increase in certain New York State gross receipts taxes, which
were billed to customers, boosted 1992 revenues by $2 million.
Natural gas operating expenses increased $28 million, or
13%, in 1993 compared to 1992. The increase in natural gas
purchased was primarily due to higher costs of natural gas
amounting to $12 million. Federal income taxes increased $3
million due to higher pre-tax book income. Natural gas operating
expenses increased $5 million due to the corporate restructuring.
Natural gas operating expenses increased $44 million, or
25%, in 1992 compared to 1991. Natural gas purchased increased
$31 million due to an increase in the volume of natural gas
purchased. This volume increase was primarily due to the CNY
acquisition. Federal income taxes increased $4 million due to
higher pre-tax book income. Other taxes increased primarily due
to an increase of $3 million in certain New York State gross
receipts taxes and $1 million in property taxes.
Liquidity and Capital Resources
Competitive Conditions
The utility industry is rapidly changing and facing an
increasingly competitive environment. Factors contributing to
this competitive environment are: the National Energy Policy Act
of 1992 (Energy Policy Act), which provides open access at the
wholesale level to electric transmission service, and the FERC
Order 636, which significantly affects the natural gas industry.
In addition, the Company's response to the economic pressures on
its electric industrial and other large use customers, high
purchase costs of NUGs, rising health care costs, increasing
taxes, weak economic conditions, conservation programs, and
compliance with environmental laws and regulations are all
factors that continue to place increased pressure on electric and
natural gas prices.
The Energy Policy Act, enacted in October 1992, is expected
to result in major changes to the utility industry. Certain
provisions of the Energy Policy Act amended the Public Utility
Holding Company Act of 1935 (PUHCA). These amendments encourage
greater competition in the supply market by establishing a new
category of wholesale electric generators that are exempt from
PUHCA regulation. The Energy Policy Act also enables the FERC to
order utilities to provide open access to transmission systems
for wholesale transactions, expanding opportunities for utilities
and NUGs to enter new and existing wholesale markets. These
developments serve to underscore the increasingly competitive
environment for utilities.
The Company's five-year strategic plan is designed to
address the competitive, rapidly changing utility industry. The
Company's objective is to remain competitive in its core
businesses in the face of increased competition. One of the key
strategies to meet competition is to improve customer value by
becoming a low-cost provider of energy services in the Northeast.
A major challenge to the Company's Electric Business Unit is
to retain and grow its industrial base. The competitive energy
supply options currently available to the Company's industrial
customers include self-generation, shifting production to plants
in other locations, or relocation. During 1993, the Company
received PSC approval for a flexible, negotiable rate tariff for
some of its high-use industrial customers. Discounts negotiated
in agreements under this tariff are not expected to have a
material effect on the Company's 1994 earnings. Two agreements
have been negotiated which eliminated threats of self-generation
and relocation.
The PSC currently has a generic proceeding to study the
broad subject of flexible, competitive rates, and will establish
guidelines for the Company and other New York State utilities
during 1994. Also in late 1993, the PSC instituted a proceeding
to address issues associated with the restructuring of the
emerging competitive natural gas market. The PSC intends to
investigate services provided by New York State gas utilities
after FERC Order 636 by the 1994-1995 heating season.
In November 1993, the Company filed with the PSC an
additional flexible, negotiable rate tariff to address
opportunities for new load. The proposed tariff is for large
additions to load (at least 500 kilowatts [kw]) for new or
existing industrial and some commercial customers. The tariff
will assist the Company in attracting new customers whose
location or expansion decisions are influenced by electricity
costs. Smaller customers will be assisted by a concurrent
proposal to increase the Company's existing economic development
incentives by one cent per kilowatt-hour. The Company has
proposed and will continue to propose revisions or additional
tariffs to respond to the opportunities or risks that develop in
a changing electric utility industry.
A major challenge to the Company's Gas Business Unit is FERC
Order 636, which became effective in November 1993, and requires
interstate natural gas pipeline companies to offer customers
unbundled or separate services equivalent to their former sales
service. With the unbundling of services, primary responsibility
for reliable natural gas supply will shift from interstate
pipeline companies to local distribution companies, such as the
Company. This should result in increased direct access to low
cost natural gas supplies by local distribution companies and end
users. One goal of FERC Order 636 is to provide equitable access
to interstate pipeline capacity. FERC Order 636 will
substantially restructure the interstate natural gas market and
intensify competition within the natural gas industry. FERC
Order 636 will allow the Company, subject to PSC approval, to
restructure rates and provide multiple service options to its
customers.
In July 1993, certain interstate pipelines serving the
Company began implementing restructured services in compliance
with FERC Order 636. The remaining pipelines implemented
restructured services by November 1993. As a result of these
restructuring changes, pipelines have incurred and will continue
to incur transition costs. These transition costs include those
associated with restructuring existing natural gas supply
contracts, the unrecovered natural gas cost that would otherwise
have been billable to pipeline customers under previously
existing rules, costs of assets needed to implement the order,
and stranded investment costs. FERC Order 636 allows pipelines
to recover all prudently incurred costs from their customers.
The Company's liability for transition costs will be based on the
pipelines' filings with FERC to recover transition costs. Only a
few of those filings have been made. The Company recorded an
estimated liability for transition costs of approximately $29
million. The Company also recorded a deferred asset for that
amount since it is currently recovering transition costs from its
customers through its gas adjustment clause and believes that
such costs will continue to be recoverable from its customers.
The Company has developed a more aggressive and accelerated
set of strategies in response to the increased challenges of
competition which are necessary to achieve the objectives
outlined in the Company's five-year strategic plan. The
following represent strategies being implemented:
- Reduce forecasted 1994 capital expenditures by one-third, or
approximately $100 million. Additional reductions will be made
in 1995 and 1996.
- Reduce operating and maintenance expenses by five percent in
1994 and again in 1995. By 1995, this will save about $40
million annually. During 1993, the Company reduced its work
force by 200 through attrition. In addition, as part of the O&M
reduction, the Company's work force was further reduced by about
600 through an early retirement opportunity program and
involuntary severance.
- Streamline the field organization to eliminate walk-in
customer service at 28 locations, and to close up to 10 electric
and natural gas operations facilities statewide.
- Place two generating units on long-term cold standby.
- Continue to reduce NUG costs. The Company's previous NUG
contract terminations and renegotiations will save customers more
than $1 billion over the terms of the contracts.
- Continue to reduce capital costs. Since 1988 the Company
has refinanced over $1.4 billion in securities, and reduced
annual interest expense by more than $55 million.
The cost of the corporate restructuring was $26 million and
was a one-time charge against the Company's 1993 earnings. The
restructuring reduced 1993 earnings available for common stock by
approximately $17.2 million or 25 cents per share. Included in
this amount are $13.2 million for a voluntary early retirement
program, $3.2 million for an involuntary severance program, and
$.8 million for the elimination and closing of operations
facilities. The Company expects to recoup the one-time charge
from lower O&M costs in approximately one year.
As part of the Company's effort to meet competition and
minimize future price increases associated with uneconomical
power purchases from NUGs, it negotiated the termination of two
cogeneration projects. This effort, along with the termination
of NUG contracts due to developers' failures to meet contract
obligations, will save customers nearly $1 billion over the terms
of the contracts. The Company has also recently negotiated
amendments with two NUGs whereby the Company may direct the NUGs
to reduce their output or shut down for limited periods each
year. During these periods, lower-cost generation will replace
the NUG energy and result in additional customer savings. The
Company is negotiating with other NUGs for similar amendments.
The Company has on line and under contract 362 megawatts
(mw) of NUG power. In addition, another 240 mw of NUG power is
under construction. The Company is required to make payments
under these contracts only for the power it receives. During
1993, 1992, and 1991, the Company purchased approximately $138
million, $71 million, and $30 million, respectively, of NUG
power. The Company estimates that it will purchase
approximately $255 million, $291 million, and $335 million of NUG
power for the years 1994, 1995, and 1996, respectively. Increases
in NUG power purchase costs are expected to be a significant
contributor to price increases over the next three years.
Diversification
Diversification will play an important role in the Company's
future. While the strength of the Company's core electric and
natural gas businesses remains its focus, and while the Company
will not compromise its financial integrity, it is actively
evaluating a number of corporate development opportunities for
investment to help augment future earnings and dividend growth.
In April 1992, the PSC issued an order allowing the Company to
invest up to 5% of its consolidated capitalization (approximately
$175 million at December 31, 1993) in one or more subsidiaries
that may engage or invest in energy-related or environmental
services businesses and provide related services. In May 1993,
NGE Enterprises, Inc. (NGE), a wholly-owned subsidiary of the
Company, formed a computer software company, EnerSoft Corporation
(EnerSoft), to produce and market software applications for
natural gas utilities in the post-FERC Order 636 environment.
This represents NGE's initial diversified investment.
In October 1993, EnerSoft began a strategic alliance with
the New York Mercantile Exchange to develop an information
superhighway that will provide the natural gas industry with a
single system for monitoring and trading natural gas and pipeline
capacity in the North American market. NGE invested
approximately $9 million in EnerSoft through February 1994.
The Company and NGE plan to develop two natural gas storage
projects. One of the projects, which will be regulated by the
PSC, is expected to cost approximately $14 million and will be
used to supplement the Company's natural gas supply.
Construction of this project is scheduled to begin in 1994 and it
is expected to be operating for the 1995-96 heating season. The
other project, which will be regulated by the FERC, is an equal
partnership between NGE and ANR Storage, Inc., and is expected to
cost approximately $44 million in total. The entire capacity of
this project will be marketed to local distribution companies and
NUGs, as well as marketers, producers, and end users of natural
gas. Construction of this project is scheduled to begin in 1995
and it is expected to be operating for the 1996-1997 heating
season.
Financing Activities
The Company believes that maintaining a high degree of
financial integrity and flexibility is critical to success in an
increasingly competitive environment. The Company intends to
build on the financial improvements realized over the past
several years with a goal of achieving a 50% common equity ratio.
New money needs are expected to be minimal and excess cash
generated from reduced construction expenditures will be used to
further manage the Company's capital structure (See Investing
Activities - estimated sources and uses of funds for 1994-1996).
The PSC adopted a new, innovative approach in December 1993
when it issued an order to the Company that provides for advanced
approval for financings during the Company's three-year rate
settlement. That order includes authorization for refundings of
first mortgage bonds, preferred stock, and tax-exempt pollution
control notes, issuance of common stock through the Dividend
Reinvestment and Stock Purchase Plan (DRP), and issuances of
other securities as required. With this order, the Company has
the flexibility to achieve its financial goals of further
reducing financing costs and improving its financial health as
market conditions allow.
The common stock equity ratio remained stable during 1993.
Issuance of shares under the DRP was offset by the issuance of
$100 million of preferred stock and $70 million of tax-exempt
pollution control notes in December 1993. The Company received
$38.4 million from the issuance of 1.2 million shares of common
stock through the DRP.
Common stock dividends paid in 1993 increased 5% over 1992
reflecting the increase in common stock outstanding and an
increase in the dividend paid from $2.14 to $2.18 per share.
The Company's dividend payout ratio has been gradually
rising over the past several years, primarily as a result of
declining earnings. These weak earnings put additional pressure
on an already high dividend payout ratio at a time when growing
competition dictates that we consider a more moderate dividend
policy. We must significantly improve earnings if we are to
continue even modest annual dividend increases.
The Company sold $25 million of 6.30% preferred stock, $50
million of Adjustable Rate Series B preferred stock, and $25
million of 7.40% preferred stock in December 1993. The net
proceeds were used to redeem $25 million of 8.80% preferred stock
and $45 million of Adjustable Rate Series A preferred stock in
January 1994, and $25 million of 8.48% preferred stock in
February 1994. Those refundings will save approximately $1.8
million annually. After those refundings, the capital structure
will be 49.8% long-term debt, 7.1% preferred stock, and 43.1%
common stock equity.
In February 1993, the Company redeemed, at par, through a
sinking fund provision in our mortgage, the remaining $22.5
million of 10 5/8% Series first mortgage bonds due 2018.
In February 1993, the Company priced $100 million of 6.05%
tax-exempt pollution control bonds, due 2034. Proceeds from the
sale, which will be delivered in April 1994, will be used to
redeem, at a premium, $60 million of 12% pollution control bonds,
due 2014, and $40 million of 12.3% pollution control bonds, due
2014. The refunding of those bonds in 1994 will save
approximately $5.3 million annually in interest costs.
In April 1993, the Company sold $50 million of 7.55% Series
first mortgage bonds due 2023. Net proceeds from the sale were
used in connection with the redemption of $50 million of the
9 1/4% Series due 2016. The refunding of those bonds will save
approximately $300,000 annually in interest costs.
In July 1993, the Company sold $100 million of 7.45% Series
first mortgage bonds due 2023. Net proceeds from the sale were
used in connection with the redemption of $100 million of the 9%
Series due 2017. The refunding of those bonds will save
approximately $650,000 annually in interest costs.
In November 1993, the Company redeemed $50 million of the
8 5/8% Series first mortgage bonds due 1996, at a premium.
Proceeds for the redemption were provided by a borrowing under
the Company's revolving credit agreement. The refunding of those
bonds will save approximately $2 million annually in interest
costs.
In December 1993, $70 million of 5.70% tax-exempt pollution
control notes, due 2028, were issued by a governmental authority
on behalf of the Company. Proceeds from the sale will be used to
finance a portion of the costs incurred in the construction of
certain solid waste disposal and other related facilities at the
Company's Milliken Generating Station.
The Company has reduced its embedded cost of long-term debt
to 7.2% at the end of 1993 from 9.2% in 1988. The Company has
refinanced more than $1.2 billion in long-term debt since 1988,
and reduced annual interest expense by more than $55 million.
Unless interest rates fall further, however, it will be difficult
to significantly improve from the 7.2% level. All opportunities
continue to be pursued aggressively.
In February 1994, the Company redeemed, at par, through a
sinking fund provision in its mortgage, $23 million of 8 5/8%
Series first mortgage bonds due 2007.
In February 1994, $37.5 million of tax-exempt pollution
control notes were issued by a governmental authority on behalf
of the Company. The notes will have several interest rate
options and have an initial rate of 2.4% through April 13, 1994.
Proceeds from the sale will be used to redeem $37.5 million of
annual adjustable rate pollution control notes, due 2015, in
March 1994.
The Company uses interim financing in the form of short-term
unsecured notes, usually commercial paper, to finance certain
refundings and construction expenditures and for other corporate
purposes, thereby providing flexibility in the timing and amounts
of long-term financings. There was $50.2 million of commercial
paper outstanding at December 31, 1993, at a weighted average
interest rate of 3.5%. The weighted average interest rate during
1993 was 3.4%.
The Company also has a revolving credit agreement with
certain banks that provides for borrowing up to $200 million to
July 31, 1997. The Company had an outstanding $50 million loan
under this agreement at December 31, 1993, at an interest rate of
4.06%.
In June 1993, the Company's first mortgage bonds and
unsecured pollution control notes were upgraded by Standard &
Poor's (S&P). The investment rating agency stated that the
higher ratings reflect expected continued improvements in the
Company's financial condition as a result of the Company's three-
year rate settlement, which was pending at the time of the
upgrade, aggressive cost controls, and limited new money needs.
S&P also noted that regulatory adjustment mechanisms, such as
electric revenue decoupling and natural gas weather
normalization, should add stability to earnings.
In October 1993, S&P completed its review of the U.S.
investor-owned utility industry and concluded that more stringent
financial benchmarks were appropriate for electric utilities to
counter increased competition and mounting business risk. As a
result, it revised the rating outlook downward for about one-
third of the utility industry, including the Company. However,
the Company's ratings were not changed.
Investing Activities
The Company's 1993 capital expenditures for its core
electric and natural gas businesses totaled approximately $245
million. Most of the expenditures were for the extension of
service and for improvements at existing facilities.
Capital expenditures for 1994-1996 have been significantly
reduced from previously forecasted levels. This represents one
of many actions the Company is taking to address competition (See
Competitive Conditions). Capital expenditures for 1994-1996 will
be primarily for extension of service, necessary improvements at
existing facilities, and compliance with the Clean Air Act
Amendments of 1990 (See Environmental Matters). The Company
forecasts that its current reserve margin, coupled with more
efficient use of energy (See Conservation Programs) and
generation from NUGs, will eliminate the need for additional
generating capacity until after the year 2005.
As part of the Company's effort to reduce costs, one of two
generating units at each of its Goudey and Greenidge Generating
Stations will be placed on long-term cold standby. These actions
are being taken because the abundance of power in the Northeast
has driven down wholesale prices. These units will continue to
be utilized to provide electrical system support.
The following table provides information on the Company's
estimated sources and uses of funds for 1994-1996. This forecast
is subject to periodic review and revision, and actual
construction costs may vary because of revised load estimates,
imposition of additional regulatory requirements, and the
availability and cost of capital.
1994 1995 1996 Total
---- ---- ---- -----
Sources of funds (Millions)
Internal funds $254 $265 $269 $788
Long-term financing
Debt and stock proceeds 413 141 80 634
Debt proceeds held in trust 34 8 - 42
---- ---- ---- -----
Net financing proceeds 447 149 80 676
Increase (decrease) in
short-term debt (50) - - (50)
Decrease (increase) in
temporary cash investments 89 (69) (52) (32)
---- ---- ---- ------
Total $740 $345 $297 $1,382
==== ==== ==== ======
Uses of funds
Construction
Cash expenditures $202 $193 $193 $588
AFDC 8 7 7 22
---- ---- ---- ------
Total construction 210 200 200 610
Retirement of securities and
sinking fund obligations 501 108 63 672
Working capital and deferrals 29 37 34 100
---- ---- ---- ------
Total $740 $345 $297 $1,382
==== ==== ==== ======
As shown in the preceding table, internal sources of funds
represent 129% of construction expenditures for 1994-1996.
Conservation Programs
The Company has implemented a number of demand-side
management (DSM) programs. As a result of its three-year rate
settlement agreement (See Regulatory Matters), incentives earned
for conducting efficient DSM programs were reduced from 15% to 5%
of the net resource savings achieved by these DSM programs. For
1994, the Company expects to earn approximately $3 million in
incentives as a result of these DSM programs.
In 1993, the Company's customers saved approximately 282
million kilowatt-hours (kwh) on an annualized basis through the
Company's DSM programs. The implementation of these programs
cost $48 million in 1993 and will cost approximately $16 million
in 1994 with estimated customer savings of 113 million kwh on an
annualized basis. The Company has approximately $73 million and
$44 million of deferred DSM program costs on the Consolidated
Balance Sheets at December 31, 1993, and 1992, respectively. The
two-year (1993-1994) DSM plan, which has received PSC approval,
has been modified to improve cost-effectiveness and reduce rate
impacts.
Environmental Matters
The Company continually assesses actions that may need to be
taken to ensure compliance with changing environmental laws and
regulations. Compliance programs will increase the cost of
electric and natural gas service by requiring changes to the
Company's operations and facilities. Historically, rate recovery
has been authorized for the cost incurred for compliance with
environmental laws and regulations.
Due to existing and proposed legislation and regulations,
and legal proceedings commenced by governmental bodies and
others, the Company may also incur costs from the past disposal
of hazardous substances produced during the Company's operations
or those of its predecessors. The Company has been notified by
the EPA and the NYSDEC that it is among the potentially
responsible parties (PRPs) who may be liable to pay for costs
incurred to remediate certain hazardous substances at seven waste
sites, not including the Company's inactive gas manufacturing
sites, which are discussed below. With respect to the seven
sites, five sites are included in the New York State Registry of
Inactive Hazardous Waste Sites (New York State Registry).
Any liability may be joint and several for certain of these
sites. The ultimate cost to remediate these sites will be
dependent on such factors as the remedial action plan selected,
the extent of site contamination, and the portion attributed to
the Company. At December 31, 1993, the Company recorded a
liability in the Consolidated Balance Sheets related to four of
these seven waste sites of $1.8 million. The Company has
notified the NYSDEC that it believes it has no responsibility at
two sites and has already incurred expenditures related to the
remediation at the remaining site. A deferred asset has also
been recorded in the amount of $2.6 million, of which $.8 million
relates to costs that have already been incurred. The Company
believes it will recover these costs, since the PSC has allowed
other utilities to recover these types of remediation costs and
has allowed the Company to recover similar costs in rates, such
as investigation and cleanup costs relating to inactive gas
manufacturing sites. This $1.8 million estimate was derived by
multiplying the total estimated cost to clean up a particular
site by the related Company contribution factor. Estimates of
the total cleanup costs were determined by using information
related to a particular site, such as investigations performed to
date at a site or from the data released by a regulatory agency.
In addition, this estimate was based upon currently available
facts, existing technology, and presently enacted laws and
regulations. The contribution factor is calculated using either
the Company's percentage share of the total PRPs named, which
assumes all PRPs will contribute equally, or the Company's
estimated percentage share of the total hazardous wastes
disposed of at a particular site, or by using a 1% contribution
factor for those sites at which it believes that it has
contributed a minimal amount of hazardous wastes. The Company
has notified its former and current insurance carriers that it
seeks to recover from them certain of these cleanup costs.
However, the Company is unable to predict the amount of insurance
recoveries, if any, that it may obtain.
A number of the Company's inactive gas manufacturing sites
have been listed in the New York State Registry. The Company has
filed petitions to delist the majority of the sites. The
Company's program to investigate and initiate remediation at its
38 known inactive gas manufacturing sites has been extended
through the year 2000. Expenditures over this time period are
estimated to be $25 million. This estimate was determined by
using the Company's experience and knowledge related to these
sites as a result of the investigation and remediation that the
Company has performed to date. It is based upon currently
available facts, existing technology, and presently enacted laws
and regulations. This liability, to investigate and initiate
remediation, as necessary, at the known inactive gas
manufacturing sites is reflected in the Company's Consolidated
Balance Sheets at December 31, 1993 and 1992. The Company also
has recorded a corresponding deferred asset, since it expects to
recover such expenditures in rates, as the Company has previously
been allowed by the PSC to recover such costs in rates. The
Company has notified its former and current insurance carriers
that it seeks to recover from them certain of these cleanup
costs. However, the Company is unable to predict the amount of
insurance recoveries, if any, that it may obtain.
The Clean Air Act Amendments of 1990 (1990 Amendments) will
result in significant expenditures of approximately $178 million,
on a present value basis, over a 25-year period, for all capital
and operating and maintenance expenses related to the reduction
of sulfur dioxide and nitrogen oxides at several of the Company's
coal-fired generating stations, of which $51 million has been
incurred as of December 31, 1993. The Company's current estimate
is a significant reduction from its prior estimate, primarily due
to the postponement of the construction of a flue gas
desulfurization (FGD) system at its Homer City Generating
Station. The Company plans to re-evaluate the need to construct
an FGD system at the Homer City Generating Station in 1995, since
its present strategy to bank Phase I emissions allowances for use
during Phase II, as discussed below, will allow the Company to
meet Phase II allowance requirements through the year 2005. The
cost to comply with the sulfur dioxide and nitrogen oxide
limitations includes the construction of an innovative FGD system
and a nitrogen oxide reduction system expected to be completed in
1995 at the Company's Milliken Generating Station. The Company
estimates that approximately a 1% electric rate increase will be
required for the cost of reducing sulfur dioxide and nitrogen
oxide emissions in both Phase I (begins January 1, 1995) and
Phase II (begins January 1, 2000). As a result of the 1990
Amendments, the Company plans to reduce its annual sulfur dioxide
emissions by an amount that will allow the Company to meet the
sulfur dioxide levels established for the Company, which is
approximately a 49% reduction from approximately 138,000 tons in
1989 to 71,000 tons by the year 2000.
The cost of controlling toxic emissions under the 1990
Amendments, if required, cannot be estimated at this time.
Regulations may be adopted at the state level which would limit
toxic emissions even further, at an additional cost to the
Company. The Company anticipates that the costs incurred to
comply with the 1990 Amendments will be recoverable through rates
based on previous rate recovery of required environmental costs.
The 1990 Amendments require the U.S. Environmental
Protection Agency (EPA) to allocate annual emissions allowances
to each of the Company's coal-fired generating stations based on
statutory emissions limits. An emissions allowance represents an
authorization to emit, during or after a specified calendar year,
one ton of sulfur dioxide. During Phase I, the Company estimates
that it will have allowances in excess of the affected coal-fired
generating stations' actual emissions. The Company's present
strategy is to bank these allowances for use in later years. By
using a banking strategy, it is estimated that Phase II allowance
requirements will be met through the year 2005 by utilizing the
allowances banked during Phase I, which includes the extension
reserve allowances discussed below, together with the Company's
Phase II annual emissions allowances. This strategy could be
modified should market or business conditions change. In
addition to the annual emissions allowances allocated to the
Company by the EPA, the Company will receive a portion of the
extension reserve allowances issued by the EPA to utilities
electing to build scrubbers, as a result of the pooling agreement
that it entered into with other utilities who were also eligible
to receive some of these extension reserve allowances.
As a result of existing and new solid waste disposal
legislation and regulations in Pennsylvania, the Company will
incur approximately $24 million, on a present value basis, of
additional costs over the next 30 years, beginning in 1994, at
the Homer City Generating Station. These costs will be incurred
to install new equipment, modify or replace existing equipment,
and improve the design of a proposed expansion of disposal
facilities. The Company expects to recover these expenditures in
rates, since the Company has been allowed by the PSC to recover
similar costs in rates, such as groundwater protection costs to
meet permit conditions and regulatory requirements.
Regulatory Matters
In September 1993, the Company reached a three-year electric
and natural gas rate settlement agreement (Agreement) with the
PSC. The new electric and natural gas rates became effective
September 4, 1993.
The allowed return on equity is 10.8% in year one, 11.4% in
year two, and 11.4% (subject to an indexing mechanism) in year
three. Shareholders will be allowed to keep 100% of any earnings
in excess of the allowed return in year one. Shareholders and
customers will share, on a 50%/50% basis, any earnings in excess
of the allowed return in years two and three.
The Agreement also includes a modified revenue decoupling
mechanism (RDM) for electric sales. Rates are based on sales
forecasts. Since actual sales may differ significantly from
forecasted sales because of conservation efforts, unusual
weather, or changing economic conditions, the revenue collected
may be more or less than forecast. Subject to the caps described
below, the modified RDM will let the Company adjust for most of
the differences between forecasted and actual sales. For
example, if revenues exceed the forecast for a given year, the
excess would be passed back to customers in a future year. If
revenues are below the forecast, customers would receive a
surcharge in a future year. The Company will share excesses or
shortfalls from most large commercial and industrial sales
revenues on a 70%/30% (customer/stockholder) basis.
Customer savings for production and transmission operating
costs of $21 million will be imputed over three years, $7 million
each year, whether or not they are realized.
Incentives for customer service, production cost, and DSM
could increase the allowed return to 12.3% or decrease it to
9.95% in year one, increase it to 13.05% or decrease it to 10.4%
in year two, and increase it to 13.25% or decrease it to 10.2% in
year three.
The electric and natural gas rate increases discussed below
represent eleven months for year one and twelve months for years
two and three.
The estimated total electric price increases below include
base rate increases allowed by the Agreement plus estimates of
fuel and purchased power increases which will be collected
through the Fuel Adjustment Clause (FAC). Actual fuel and
purchased power costs could vary from estimates causing the
estimated FAC and total electric price increases below to change.
Base Rate Estimated FAC Total Electric
(Dollar Amounts in Millions)
Year 1 $60.5 4.4% $39.1 3.0% $99.6 7.4%
Year 2 $70.3 4.8% $39.2 2.8% $109.5 7.6%
Year 3 $57.4 3.6% $30.4 2.0% $87.8 5.6%
The natural gas base rate increases allowed by the Agreement
are $7.5 million, or 2.9%, $8.2 million, or 3.0%, and $7.2
million, or 2.5%, in years one, two, and three, respectively.
They do not include changes in natural gas costs, which will be
collected through the Gas Adjustment Clause. Natural gas costs
can be expected to rise and fall with overall natural gas market
conditions. Such fluctuations will affect the total natural gas
price increases.
The Agreement also provides for the stated electric and
natural gas base rate increases to be adjusted up or down in the
second and third years, as well as the year after the Agreement
period (year four). These adjustments will depend on several
factors, such as electric sales and incentive mechanisms. The
Agreement provides that no cap would apply to any downward
revision to base rates for electric and natural gas service. The
electric base rate increases could be increased by up to 1.5% in
years two and three and 1.6% in year four (the caps). The
natural gas base rate increases could also be increased by up to
1% in year two and 1.2% in year three. The Agreement does not
specify a cap for natural gas base rates for year four.
Item 8. Financial statements and supplementary data
New York State Electric & Gas Corporation
Consolidated Statements of Income
Year Ended December 31 1993 1992 1991
- ----------------------------------------------------------------------------
(Thousands, except Per Share Amounts)
Operating Revenues
Electric . . . . . . . . . . . . . . . . $1,527,362 $1,451,525 $1,367,936
Natural gas. . . . . . . . . . . . . . . 272,787 240,164 187,879
---------- ---------- ----------
Total Operating Revenues . . . . . . $1,800,149 1,691,689 1,555,815
---------- ---------- ----------
Operating Expenses
Fuel used in electric generation . . . . 245,283 262,531 274,877
Electricity purchased (Note 9) . . . . . 161,967 95,026 45,808
Natural gas purchased. . . . . . . . . . 141,635 126,815 99,528
Other operating expenses . . . . . . . . 349,177 318,680 279,364
Restructuring expenses (Notes 6 and 7) . 26,000 - -
Maintenance. . . . . . . . . . . . . . . 111,757 102,500 110,131
Depreciation and amortization (Note 1) . 164,568 158,977 152,380
Federal income taxes (Notes 1 and 2) . . 94,144 102,456 94,447
Other taxes (Note 12). . . . . . . . . . 204,962 200,941 178,185
---------- ---------- ----------
Total Operating Expenses . . . . . . . 1,499,493 1,367,926 1,234,720
---------- ---------- ----------
Operating Income. . . . . . . . . . . . . 300,656 323,763 321,095
Other Income and Deductions . . . . . . . 6,471 12,036 6,076
---------- ---------- ----------
Income Before Interest Charges. . . . . . 307,127 335,799 327,171
---------- ---------- ----------
Interest Charges
Interest on long-term debt . . . . . . . 134,330 145,822 151,649
Other interest . . . . . . . . . . . . . 11,120 9,566 11,877
Allowance for borrowed funds
used during construction. . . . . . . . (4,351) (3,557) (4,998)
---------- ---------- ----------
Interest Charges - Net . . . . . . . . 141,099 151,831 158,528
---------- ---------- ----------
Net Income. . . . . . . . . . . . . . . . 166,028 183,968 168,643
Preferred Stock Dividends . . . . . . . . 20,638 20,995 20,330
---------- ---------- ----------
Earnings Available for Common Stock . . . $145,390 $162,973 $148,313
========== ========== ==========
Earnings Per Share. . . . . . . . . . . . $2.08 $2.40 $2.36
Average Shares Outstanding. . . . . . . . 69,990 67,972 62,906
The notes on pages 50 through 73 are an integral part of the
financial statements.
New York State Electric & Gas Corporation
Consolidated Balance Sheets
December 31 1993 1992
- -------------------------------------------------------------------------------
(Thousands)
Assets
Utility Plant, at Original Cost (Note 1)
Electric (Note 8). . . . . . . . . . . . . . . . . . . $4,777,368 $4,573,444
Natural gas. . . . . . . . . . . . . . . . . . . . . . 381,389 352,059
Common . . . . . . . . . . . . . . . . . . . . . . . . 158,986 157,979
---------- ----------
. . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,317,743 5,083,482
Less accumulated depreciation. . . . . . . . . . . . . 1,541,456 1,427,793
---------- ----------
Net Utility Plant in Service. . . . . . . . . . . . 3,776,287 3,655,689
Construction work in progress. . . . . . . . . . . . . 143,859 177,566
---------- ----------
Total Utility Plant . . . . . . . . . . . . . . . . 3,920,146 3,833,255
Other Property and Investments, net . . . . . . . . . . 73,537 59,157
Current Assets
Cash and cash equivalents (Notes 1 and 10) . . . . . . 4,264 3,968
Special deposits (Note 10) . . . . . . . . . . . . . . 145,335 96,432
Accounts receivable, net (Note 1). . . . . . . . . . . 181,586 171,683
Fuel, at average cost. . . . . . . . . . . . . . . . . 54,791 69,077
Materials and supplies, at average cost. . . . . . . . 48,910 50,637
Prepayments. . . . . . . . . . . . . . . . . . . . . . 30,092 37,897
Accumulated deferred federal income
tax benefits (Notes 1 and 2). . . . . . . . . . . . - 1,182
---------- ----------
Total Current Assets. . . . . . . . . . . . . . . . 464,978 430,876
Deferred Charges (Note 1)
Unfunded future federal income
taxes (Notes 1 and 2) . . . . . . . . . . . . . . . 380,056 393,720
Unamortized debt expense . . . . . . . . . . . . . . . 112,059 96,378
Demand-side management program costs . . . . . . . . . 73,113 44,049
Other. . . . . . . . . . . . . . . . . . . . . . . . . 252,127 220,481
---------- ----------
Total Deferred Charges. . . . . . . . . . . . . . . 817,355 754,628
---------- ----------
Total Assets. . . . . . . . . . . . . . . . . . . . $5,276,016 $5,077,916
========== ==========
The notes on pages 50 through 73 are an integral part of the financial
statements.
New York State Electric & Gas Corporation
Consolidated Balance Sheets
December 31 1993 1992
- ------------------------------------------------------------------------------
(Thousands)
Capitalization and Liabilities
Capitalization
Common stock equity
Common stock ($6.66 2/3 par value, 90,000,000
shares authorized and 70,595,985 and 69,439,397
shares issued and outstanding at December 31,
1993 and 1992, respectively) . . . . . . . . . . $470,640 $462,929
Capital in excess of par value. . . . . . . . . . 824,943 796,505
Retained earnings . . . . . . . . . . . . . . . . 320,114 327,040
---------- ----------
Total common stock equity. . . . . . . . . . . . . . . 1,615,697 1,586,474
Preferred stock redeemable solely at the option of
the Company (Note 4). . . . . . . . . . . . . . . . 140,500 160,500
Preferred stock subject to mandatory redemption
requirements (Notes 4 and 10) . . . . . . . . . . . 125,000 106,900
Long-term debt (Notes 3 and 10). . . . . . . . . . . . 1,630,629 1,777,027
---------- ----------
Total Capitalization. . . . . . . . . . . . . . . 3,511,826 3,630,901
Current Liabilities
Current portion of long-term debt and preferred
stock (Notes 3 and 4) . . . . . . . . . . . . . . . 332,709 115,659
Commercial paper (Notes 5 and 10). . . . . . . . . . . 50,200 64,100
Accounts payable and accrued liabilities . . . . . . . 111,481 95,996
Interest accrued (Note 10) . . . . . . . . . . . . . . 31,348 37,690
Accumulated deferred federal income taxes
(Notes 1 and 2) . . . . . . . . . . . . . . . . . . 1,132 -
Other. . . . . . . . . . . . . . . . . . . . . . . . . 89,443 65,073
---------- ----------
Total Current Liabilities . . . . . . . . . . . . 616,313 378,518
Deferred Credits
Accumulated deferred investment tax credits
(Notes 1 and 2) . . . . . . . . . . . . . . . . . . 138,478 141,729
Excess deferred federal income taxes (Notes 1 and 2) . 36,378 58,188
Other. . . . . . . . . . . . . . . . . . . . . . . . . 149,620 107,160
---------- ----------
Total Deferred Credits. . . . . . . . . . . . . . 324,476 307,077
Accumulated Deferred Federal Income Taxes
(Notes 1 and 2)
Unfunded future federal income taxes . . . . . . . . . 380,056 393,720
Other. . . . . . . . . . . . . . . . . . . . . . . . . 416,545 342,700
---------- ----------
Total Accumulated Deferred Federal
Income Taxes . . . . . . . . . . . . . . . . . . 796,601 736,420
Commitments and Contingencies (Note 9). . . . . . . . . 26,800 25,000
---------- ----------
Total Capitalization and Liabilities. . . . . . . $5,276,016 $5,077,916
========== ==========
The notes on pages 50 through 73 are an integral part of the financial
statements.
New York State Electric & Gas Corporation
Consolidated Statements of Cash Flows
Year Ended December 31 1993 1992 1991
- ------------------------------------------------------------------------------
(Thousands)
Operating Activities
Net Income . . . . . . . . . . . . . . . . . . . . $166,028 $183,968 $168,643
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization. . . . . . . . . . 164,568 158,977 152,380
Deferred fuel and purchased gas. . . . . . . . . (10,671) (14,645) 2,507
Federal income taxes and investment tax credits
deferred - net . . . . . . . . . . . . . . . . 50,761 52,039 59,626
Unbilled revenue recognition (Note 1). . . . . . (11,557) (22,228) (40,147)
Demand-side management program costs . . . . . . (29,064) (22,863) (15,118)
Restructuring expenses . . . . . . . . . . . . . 26,000 - -
Changes in current operating assets and liabilities,
net of effects from the purchase of Columbia Gas
of New York, Inc. in 1991:
Special deposits . . . . . . . . . . . . . . . . 2,438 (1,873) (4,108)
Accounts receivable excluding accounts
receivable sold. . . . . . . . . . . . . . . . (17,483) (11,936) (15,541)
Accounts receivable sold (Note 1). . . . . . . . 13,800 - -
Prepayments. . . . . . . . . . . . . . . . . . . 7,805 (878) (7,882)
Inventory. . . . . . . . . . . . . . . . . . . . 16,013 (1,417) 4,590
Accounts payable and accrued liabilities . . . . 7,384 (8,287) 5,656
Interest accrued . . . . . . . . . . . . . . . . (6,342) (5,750) (3,610)
Other-net. . . . . . . . . . . . . . . . . . . . . 32,510 (18,840) (1,110)
-------- -------- --------
Net Cash Provided by Operating Activities . . . 412,190 286,267 305,886
-------- -------- --------
Investing Activities
Utility plant construction expenditures, net of
allowance for funds used during construction
- other . . . . . . . . . . . . . . . . . . . . (265,109)(243,373)(244,037)
Proceeds received from governmental and
other sources . . . . . . . . . . . . . . . . . 22,808 322 -
Expenditures for other property and investments. . (16,975) - -
Funds set aside for construction expenditures. . . (42,437) - -
Payment for purchase of Columbia Gas of New
York, Inc., net of cash acquired . . . . . . . . - - (57,096)
-------- -------- --------
Net Cash Used in Investing Activities . . . . . (301,713)(243,051)(301,133)
-------- -------- --------
Financing Activities
Issuance of first mortgage bonds and
pollution control notes. . . . . . . . . . . . . 217,362 247,668 147,243
Proceeds from revolving credit agreement . . . . . 50,000 - -
Sale of common stock . . . . . . . . . . . . . . . 38,334 162,965 25,380
Sale of preferred stock. . . . . . . . . . . . . . 97,762 - 98,975
First mortgage bonds and preferred stock
repayments, including premiums . . . . . . . . . (326,091)(178,289)(142,715)
Increase in funds set aside for first
mortgage bond and preferred stock repayments . . (8,904) (83,096) -
Long-term notes - net. . . . . . . . . . . . . . . 8,393 (1,593) (2,322)
Commercial paper - net . . . . . . . . . . . . . . (13,900) (39,800) 30,675
Dividends on common and preferred stock. . . . . . (173,137)(165,704)(150,106)
-------- -------- --------
Net Cash Provided by (Used in) Financing
Activities. . . . . . . . . . . . . . . . . . (110,181) (57,849) 7,130
-------- -------- --------
Net Increase (Decrease) in Cash and Cash Equivalents 296 (14,633) 11,883
Cash and Cash Equivalents, Beginning of Year. . . . 3,968 18,601 6,718
-------- -------- --------
Cash and Cash Equivalents, End of Year
(Notes 1 and 10). . . . . . . . . . . . . . . . . $4,264 $3,968 $18,601
======== ======== ========
The notes on pages 50 through 73 are an integral part of the
financial statements
New York State Electric & Gas Corporation
Consolidated Statements of Changes
in Common Stock Equity
(Thousands, except Shares and Per Share Amounts)
Common Stock Capital
$6.66 2/3 Par Value in Excess Retained
Shares Amount of Par Value Earnings Total
Balance, January 1, 1991 62,430,297 $416,202 $655,892 $292,250 $1,364,344
Net income 168,643 168,643
Cash dividends declared:
Preferred stock (at serial rates)
Redeemable - optional (11,395) (11,395)
- mandatory (8,935) (8,935)
Common stock ($2.10 per share) (131,875) (131,875)
Issuance of stock:
Dividend reinvestment and stock
purchase plan 969,941 6,466 17,899 24,365
Balance, December 31, 1991 63,400,238 422,668 673,791 308,688 1,405,147
Net income 183,968 183,968
Cash dividends declared:
Preferred stock (at serial rates)
Redeemable - optional (11,164) (11,164)
- mandatory (9,831) (9,831)
Common stock ($2.14 per share) (144,621) (144,621)
Issuance of stock:
Public Offering 5,000,000 33,333 99,367 132,700
Dividend reinvestment and
stock purchase plan 1,039,159 6,928 23,347 30,275
Balance, December 31, 1992 69,439,397 462,929 796,505 327,040 1,586,474
Net income 166,028 166,028
Cash dividends declared:
Preferred stock (at serial rates)
Redeemable - optional (11,085) (11,085)
- mandatory (9,553) (9,553)
Common stock ($2.18 per share) (152,316) (152,316)
Issuance of stock:
Dividend reinvestment and
stock purchase plan 1,156,588 7,711 28,438 36,149
Balance, December 31, 1993 70,595,985 $470,640 $824,943 $320,114 $1,615,697
The notes on pages 50 through 73 are an integral part of the financial statements.
Notes to Consolidated Financial Statements
1 Significant Accounting Policies
Principles of consolidation
The consolidated financial statements include the Company's
wholly-owned subsidiaries, Somerset Railroad Corporation (SRC)
and NGE Enterprises, Inc. (NGE). All significant intercompany
balances and transactions are eliminated in consolidation.
Utility plant
The cost of repairs and minor replacements is charged to the
appropriate operating expense accounts. The cost of renewals and
betterments, including indirect cost, is capitalized. The
original cost of utility plant retired or otherwise disposed of
and the cost of removal less salvage are charged to accumulated
depreciation.
Depreciation and amortization
Depreciation expense is determined using straight-line
rates, based on the average service lives of groups of
depreciable property in service. Depreciation accruals were
equivalent to 3.4%, 3.3%, and 3.3%, of average depreciable
property for 1993, 1992, and 1991, respectively. Depreciation
expense includes the amortization of certain deferred charges
authorized by the Public Service Commission of the State of New
York (PSC).
Revenue
During 1993, 1992, and 1991, the Company recognized on the
income statement approximately $12 million, $22 million, and $40
million, respectively, of electric and natural gas unbilled
revenues that had been accrued on its balance sheet for energy
provided but not yet billed to minimize the rate increases for
these years in accordance with various PSC rate decisions. The
July 1992 rate decision allowed the Company to recognize on its
income statement, beginning in August 1992, electric and natural
gas unbilled revenues on a full accrual basis.
The Company recognizes as revenue incentives earned as the
result of conducting efficient demand-side management (DSM)
programs. The Company is collecting those incentives in rates
within approximately one year after they are recognized. During
1993, 1992, and 1991, incentives earned were $16.4 million, $15.6
million, and $12.4 million, respectively. At December 31, 1993
and 1992, approximately $14.3 million and $9.8 million,
respectively, of DSM incentives were accrued and included in
accounts receivable.
Accounts receivable
The Company has an agreement that expires in November 1996
to sell, with limited recourse, undivided percentage interests in
certain of its accounts receivable from customers. The agreement
allows the Company to receive up to $152 million from the sale of
such interests. At December 31, 1993 and 1992, accounts
receivable on the Consolidated Balance Sheets is shown net of
$152 million and $138 million, respectively, of interests in
accounts receivable sold. All fees associated with the program
are included in other income and deductions on the Consolidated
Statements of Income and amounted to approximately $5.7 million,
$6.5 million, and $9.3 million in 1993, 1992, and 1991,
respectively. Accounts receivable on the Consolidated Balance
Sheets is also shown net of an allowance for doubtful accounts of
$4 million and $1.9 million at December 31, 1993 and 1992,
respectively. Bad debt expense was $15.3 million, $11.5 million,
and $10.7 million in 1993, 1992, and 1991, respectively.
Federal income taxes
The Company adopted Statement of Financial Accounting
Standards No. 109 (SFAS 109), Accounting for Income Taxes, in
January 1993. Since the Company had been accounting for income
taxes under Statement of Financial Accounting Standards No. 96,
Accounting for Income Taxes, there was no effect on the
Consolidated Statements of Income as a result of adopting SFAS
109. However, SFAS 109 did require the Company's deferred tax
balances to be reclassified on its Consolidated Balance Sheets.
The Company files a consolidated federal income tax return
with SRC and NGE. Deferred income taxes are provided on all
temporary differences between financial statement basis and
taxable income. Investment tax credits, which reduce federal
income taxes currently payable, are deferred and amortized over
the estimated lives of the applicable property. The effect of
the alternative minimum tax, which increases federal income taxes
currently payable and generates a tax credit available for future
use, is deferred and amortized at such times as the tax credit is
used on the Company's federal income tax return.
Deferred charges
The Company defers certain incurred expenses when authorized
by the PSC. Those expenses will be recovered from customers in
the future.
Consolidated Statements of Cash Flows
The Company considers all highly liquid investments with a
maturity or put date of three months or less when acquired to be
cash equivalents. These investments are included in cash and
cash equivalents on the Consolidated Balance Sheets.
Total income taxes paid were $27.3 million, $38.5 million,
and $31.8 million for the years ended December 31, 1993, 1992,
and 1991, respectively.
Interest paid, net of amounts capitalized, was $138.2
million, $149.3 million, and $159.9 million for the years ended
December 31, 1993, 1992, and 1991, respectively.
The Company purchased all of the common stock of Columbia
Gas of New York, Inc. in 1991. In conjunction with the
acquisition, liabilities assumed were $24.9 million (fair value
of assets acquired of $82 million less cash paid of $57.1
million).
Reclassification
Certain amounts have been reclassified on the consolidated
financial statements to conform with the 1993 presentation.
2 Federal Income Taxes
Year ended December 31 1993 1992 1991
(Thousands)
Charged to operations
Current $34,989 $37,237 $22,991
Deferred - net
Accelerated depreciation 49,580 41,492 37,409
Unbilled revenues 5,073 160 13,644
Alternative minimum tax (AMT)
credit (3,194) 2,123 5,557
Demand-side management 13,479 9,324 8,589
NUG termination
agreement 4,760 6,800 -
Nine Mile No. 2 litigation
proceeds 4,756 (2,047) -
Restructuring expenses (6,965) - -
Transmission facility agreement(7,778) (1,172) (1,162)
Miscellaneous (6,198) (3,491) (9,365)
Investment tax credit (ITC)
deferred 5,642 12,030 16,784
------- -------- -------
94,144 102,456 94,447
Included in other income
Amortization of deferred ITC (8,892) (16,927) (11,297)
Miscellaneous 498 3,747 (533)
------- -------- -------
Total $85,750 $89,276 $82,617
======= ======== =======
The Company's effective tax rate differed from the statutory rate
of 35% in 1993 and 34% in 1992 and 1991 due to the following:
Year ended December 31 1993 1992 1991
(Thousands)
Tax expense at statutory rate $88,684 $92,903 $85,428
Depreciation not normalized 16,984 16,697 16,051
ITC amortization (8,892) (16,927) (11,297)
Research & Development (R&D)
credit (5,139) - -
Cost of removal (4,921) (4,079) (6,120)
Other - net (966) 682 (1,445)
------- ------- ------
Total $85,750 $89,276 $82,617
======= ======= =======
The Company's current and noncurrent deferred taxes, which
net to a tax liability of approximately $936.2 million as of
December 31, 1993, consisted of the following deferred tax assets
and liabilities:
Deferred Tax Deferred Tax
Assets Liabilities
(Thousands)
Depreciation $ 698,939
Loss on reacquired debt 28,440
Regulatory Asset (SFAS 109) 149,636
Accumulated deferred ITC 91,006
Demand-side management 35,381
NUG contract settlement costs 15,163
Alternative minimum tax credit $ 19,953
Excess tax reserve 12,603
Nine Mile No. 2 disallowed plant 19,347
Contributions in aid of construction 20,913
Capitalized interest 8,690
Other 35,369 34,521
----------- ------------
Total deferred taxes $116,875 $1,053,086
=========== ============
The Revenue Reconciliation Act (RRA) of 1993 was enacted on
August 10, 1993. Among other things, RRA 1993 provided for an
increase of 1% in the statutory corporate income tax rate and an
extension of the R&D credit until June 30, 1995.
In September 1993, the Company reached a three-year rate
settlement agreement with the PSC (Agreement) which included a
provision for the Company to petition to defer the effect of RRA
1993 until it is reflected in rates. The Company has deferred
for collection from customers $.6 million representing additional
1993 federal income taxes resulting from RRA 1993.
The Company has recorded unfunded future federal income
taxes and a corresponding receivable from customers of
approximately $381 million and $393 million as of December 31,
1993 and 1992, respectively, primarily representing the
cumulative amount of federal income taxes on temporary
depreciation differences, which were previously flowed through to
customers. Those amounts, including the tax effect of the future
revenue requirements, are being amortized over the life of the
related depreciable assets concurrent with their recovery in
rates.
The Company has approximately $20 million of AMT credits
which do not expire, and $5.1 million of R&D credits which expire
beginning in 2005.
3 Long-Term Debt
At December 31, 1993 and 1992, long-term debt was (Thousands):
First mortgage bonds
Amount
Series Due 1993 1992
8 3/8% Aug. 15, 1994 $ 100,000 $100,000
8 5/8% June 1, 1996 - 50,000
5 5/8% Jan. 1, 1997 25,000 25,000
6 1/4% Sept. 1, 1997 25,000 25,000
6 1/2% Sept. 1, 1998 30,000 30,000
7 5/8% Nov. 1, 2001 50,000 50,000
6 3/4% Oct. 15, 2002 150,000 150,000
9 3/8% Jan. 1, 2006 - 3,000
7 1/4% June 1, 2006 12,000 12,000
6 7/8% Dec. 1, 2006 25,250 25,500
8 5/8% Nov. 1, 2007 60,000 60,000
9 1/4% Apr. 1, 2016 - 50,000
9% Mar. 1, 2017 - 100,000
10 5/8% Jan. 1, 2018 - 100,000
9 7/8% Feb. 1, 2020 100,000 100,000
9 7/8% May 1, 2020 100,000 100,000
9 7/8% Nov. 1, 2020 100,000 100,000
8 7/8% Nov. 1, 2021 150,000 150,000
8.30 % Dec. 15, 2022 100,000 100,000
7.55 % Apr. 1, 2023 50,000 -
7.45 % July 15, 2023 100,000 -
--------- ---------
Total first mortgage bonds 1,177,250 1,330,500
========= =========
Pollution control notes
Interest Maturity Interest Rate Letter of Credit Amount
Rate Date Adjustment Date Expiration Date 1993 1992
12% May 1, 2014* - - 60,000 60,000
12.30% July 1, 2014* - - 40,000 40,000
2.80% Dec. 1, 2014 Dec. 1, 1994 Dec. 15, 1995 74,000 74,000
2.75% Mar. 1, 2015 Mar. 1, 1994 Mar. 15, 1995 37,500 37,500
2.50% Mar. 15, 2015 Mar. 15, 1994 Mar. 31, 1995 60,000 60,000
2.60% July 15, 2015 July 15, 1994 July 31, 1995 63,500 63,500
2.85% Oct. 15, 2015 Oct. 15, 1994 Oct. 31, 1995 30,000 30,000
2.75% Dec. 1, 2015 Dec. 1, 1994 Dec. 15, 1995 42,000 42,000
4.10% July 1, 2026 July 1, 1996 July 15, 1996 65,000 65,000
5.95% Dec. 1, 2027 - - 34,000 34,000
5.70% Dec. 1, 2028 - - 70,000 -
---------- ----------
Total pollution control notes 576,000 506,000
========== ==========
Revolving Credit Agreement Note due July 31, 1997 50,000 -
Long-term notes due December 31, 1996 36,100 27,707
CNG Transmission Corp. Note due November 10, 1996 8,862 -
Obligations under capital leases 30,902 38,804
Unamortized premium and discount on debt-net (10,776) (11,975)
---------- ----------
1,868,338 1,891,036
Less: debt due within one year-included
in current liabilities 237,709 114,009
---------- ----------
Total $1,630,629 $1,777,027
========== ==========
* Will be refunded in 1994 with proceeds from the issuance of $100 million of
6.05% pollution control notes due 2034.
At December 31, 1993, long-term debt and capital lease
payments which will become due during the next five years are:
1994 1995 1996 1997 1998
(Thousands)
$237,709 $12,552 $45,651 $102,196 $31,411
The Company's mortgage provides for a sinking and
improvement fund. This provision requires the Company to make
annual cash deposits with the Trustee equivalent to 1% of the
principal amount of all bonds delivered and authenticated by the
Trustee prior to January 1 of that year (excluding any bonds
issued on the basis of the retirement of bonds). The Company
satisfied this requirement in 1993 by depositing $22.5 million in
cash which was used to redeem in February 1993, $22.5 million of
10 5/8% Series first mortgage bonds, due 2018. The Company
satisfied this requirement in 1994 by depositing $23 million in
cash which was used to redeem in February 1994, $23 million of
8 5/8% Series first mortgage bonds, due 2007.
Mandatory annual cash sinking fund requirements are $600,000
beginning June 1, 2001, for the 7 1/4% Series and $250,000 on
December 1 in each year 1994 to 1996, for the 6 7/8% Series. The
amount increases to $500,000 and $750,000 on December 1, 1997 and
December 1, 2002, respectively, for the 6 7/8% Series.
The Company's first mortgage bond indenture constitutes a
direct first mortgage lien on substantially all utility plant.
Adjustable rate pollution control notes were issued to secure
like amounts of tax-exempt adjustable rate pollution control
revenue bonds (Revenue Bonds) issued by a governmental authority.
The Revenue Bonds bear interest at the rate indicated through the
date preceding the interest rate adjustment date. The pollution
control notes bear interest at the same rate as the Revenue
Bonds. On the interest rate adjustment date and annually
thereafter (every three years thereafter in the case of the
Revenue Bonds due July 1, 2026), the interest rate will be
adjusted, not to exceed a rate of 15%, or at the option of the
Company, subject to certain conditions, a fixed rate of interest,
not to exceed 18%, may become effective. In the case of the
Revenue Bonds due July 1, 2026, at the option of the Company,
subject to certain conditions, a fixed rate of interest may
become effective prior to the interest rate adjustment date or
each third year thereafter. Bond owners may elect, subject to
certain conditions, to have their Revenue Bonds purchased by the
Trustee.
The Company has irrevocable letters of credit which expire on
the letter of credit expiration dates and which the Company
anticipates being able to extend if the interest rate on the
related Revenue Bonds is not converted to a fixed interest rate.
Those letters of credit support certain payments required to be
made on the Revenue Bonds. If the Company is unable to extend
the letter of credit that is related to a particular series of
Revenue Bonds, that series will have to be redeemed unless a
fixed rate of interest becomes effective. Payments made under
the letters of credit in connection with purchases of Revenue
Bonds by the Trustee are repaid with the proceeds from the
remarketing of the Revenue Bonds. To the extent the proceeds are
not sufficient, the Company is required to reimburse the bank
that issued the letter of credit.
4 Preferred Stock
At December 31, 1993 and 1992, serial cumulative preferred stock was:
Shares
Par Value Authorized
Per Redeemable and Amount
Series Share Prior to Per Share Outstanding(1) 1993 1992
(Thousands)
Redeemable solely at the option of the Company:
3.75% $100 $104.00 150,000 $ 15,000 $ 15,000
4 1/2%(1949) 100 103.75 40,000 4,000 4,000
4.15% 100 101.00 40,000 4,000 4,000
4.40% 100 102.00 75,000 7,500 7,500
4.15% (1954) 100 102.00 50,000 5,000 5,000
6.48% 100 102.00 300,000 30,000 30,000
8.80% (2) 100 102.00 250,000 25,000 25,000
8.48% (3) 25 25.70 1,000,000 25,000 25,000
7.40% (4) 25 12/1/98 26.85 1,000,000 25,000 -
Thereafter 25.00
Adjustable
Rate (5) 25 25.00 1,800,000 45,000 45,000
Adjustable
Rate (6) 25 12/1/98 27.50 2,000,000 50,000 -
Thereafter 25.00
---------- ----------
235,500 160,500
Less: preferred stock redemptions within one year
- included in current liabilities 95,000 -
---------- ----------
Total $ 140,500 $ 160,500
========== ==========
Subject to mandatory redemption requirements:
9.00% (7) 100 - $ - $ 8,550
6.30% (8) 100 1/1/95 105.67 250,000 25,000 -
8.95% (9) 25 1/1/95 26.79 4,000,000 100,000 100,000
---------- ----------
125,000 108,550
Less: sinking fund requirements at par value
- included in current liabilities - 1,650
---------- ----------
Total $ 125,000 $ 106,900
========== ==========
At December 31, 1993, preferred stock redemptions and annual
redeemable preferred stock sinking fund requirements for the next
five years are:
1994 1995 1996 1997 1998
(Thousands)
$95,000 $ - $ - $5,000 $5,000
(1) At December 31, 1993, and after giving effect to the
redemptions referred to in (2), (3), and (5) below, there were
1,550,000 shares of $100 par value preferred stock, 3,800,000
shares of $25 par value preferred stock and 1,000,000 shares of
$100 par value preference stock authorized but unissued.
(2) Redeemed January 18, 1994.
(3) Redeemed February 1, 1994.
(4) The Company is restricted in its ability to redeem this
Series prior to December 1, 1998.
(5) The Adjustable Rate Serial Preferred Stock, Series A, was
redeemed January 10, 1994.
(6) The payment on the Adjustable Rate Serial Preferred Stock,
Series B, for April 1, 1994, is at an annual rate of 5.12% and
subsequent payments can vary from an annual rate of 4% to 10%,
based on a formula included in the Company's Certificate of
Incorporation. The Company is restricted in its ability to
redeem this Series prior to December 1, 1998.
(7) On October 1, 1993, 33,000 shares were redeemed at par. The
remaining 52,500 shares were redeemed at $100.50 per share on
October 13, 1993. For the years 1991 and 1992, 16,500 shares
were redeemed and cancelled annually.
(8) On January 1, in each year 2004 through 2008, the Company
must redeem 12,500 shares at par, and on January 1, 2009, the
Company must redeem the balance of the shares at par. This
Series is redeemable at the option of the Company at $105.67 per
share prior to January 1, 1995. The $105.67 price will be
reduced annually by 63 cents for the years ending 1995 through
2002; thereafter, the redemption price is $100.00. The Company
is restricted in its ability to redeem this Series prior to
January 1, 2004.
(9) On January 1, in each year 1997 through 2016, the Company
must redeem 200,000 shares at par. This Series is redeemable at
the option of the Company at $26.79 per share prior to January 1,
1995. The $26.79 price will be reduced annually by 15 cents for
the years ending 1995 through 1999; by 14 cents for the year
ending 2000; and by 15 cents for the years ending 2001 through
2005. The Company is restricted in its ability to redeem this
Series prior to January 1, 1996.
5 Bank Loans and Other Borrowings
The Company has a revolving credit agreement with certain
banks which provides for borrowing up to $200 million to July 31,
1997. At the option of the Company, the interest rate on
borrowings is related to the prime rate, the London Interbank
Offered Rate (LIBOR) or the interest rate applicable to certain
certificates of deposit. The agreement also provides for the
payment of a commitment fee which can fluctuate from .15% to
.375% depending upon the ratings of the Company's first mortgage
bonds. The commitment fee at December 31, 1993 is .1875%.
The Company had an outstanding loan of $50 million under
the revolving credit agreement at December 31, 1993, at an
interest rate of 4.06% under the LIBOR option, and did not have
any outstanding loans under this agreement at December 31, 1992.
The revolving credit agreement does not require compensating
balances.
In order to provide flexibility in the timing and amounts of
long-term financings, the Company uses interim financing in the
form of short-term unsecured notes, usually commercial paper, to
finance certain refundings and construction expenditures, and for
other corporate purposes.
Information relative to short-term borrowings is as follows:
Commercial Paper
1993 1992 1991
(Thousands)
Ending balance $50,200 $64,100 $103,900
Maximum amount outstanding $95,400 $140,000 $111,000
Average amount outstanding (1) $56,300 $31,400 $66,700
Weighted average interest rate
On ending balance 3.5% 4.0% 5.3%
During the period (2) 3.4% 4.3% 6.2%
(1) Calculated as the average of the sum of daily outstanding
borrowings.
(2) Calculated by dividing total interest expense by the average
of the sum of daily outstanding borrowings.
6 Restructuring
In the fourth quarter of 1993, the Company recorded a $26
million restructuring charge. The corporate restructuring will
reorganize the way the Company delivers services to its electric
and natural gas customers beginning in March 1994. The
restructuring reduced 1993 earnings available for common stock by
approximately $17.2 million or 25 cents per share. Included in
this amount are $13.2 million for a voluntary early retirement
program, $3.2 million for an involuntary severance program, and
$.8 million for the elimination and closing of electric and
natural gas operations facilities statewide. During 1994, the
restructuring resulted in a work force reduction throughout the
organization of approximately 600, the elimination of customer
walk-in services at 28 satellite locations, and the closing of up
to 10 electric and natural gas operations facilities statewide.
The work force reduction was accomplished through a voluntary
early retirement program (See Note 7 - Retirement Benefits) and
an involuntary severance program. 384 employees accepted the
early retirement program.
7 Retirement Benefits
Pensions
The Company has a noncontributory retirement annuity plan
that covers substantially all employees. Benefits are based
principally on the employee's length of service and compensation
for the five highest paid years out of the last 10 years of
service. It is the Company's policy to fund pension costs
accrued each year to the extent deductible for federal income tax
purposes.
The net pension benefit for 1993, 1992, and 1991 totaled
$5.7 million, $1.5 million, and $2.9 million, respectively.
Effective January 1, 1993, the retirement benefit plans for
hourly and salaried employees were combined into one plan.
Combining the two plans did not affect benefit levels.
Net pension benefit for 1993, 1992, and 1991 included the
following components:
1993 1992 1991
(Thousands)
Service cost: Benefits
earned during the year $ 17,688 $ 15,387 $ 13,252
Interest cost on projected
benefit obligation 40,710 35,253 32,096
Actual return on plan assets (77,129) (60,020) (111,749)
Net amortization and deferral 12,989 7,844 63,487
------- -------- --------
Net pension (benefit) $ (5,742) $ (1,536) $ (2,914)
======= ======== ========
The funded status of the plans at December 31, 1993 and 1992
were:
1993 1992
(Thousands)
Actuarial present value of accumulated
benefit obligation:
Vested $390,716 $287,504
Nonvested 55,476 42,286
-------- --------
Total 446,192 329,790
======== ========
Fair value of plan assets $753,292 $701,893
Actuarial present value of
projected benefit obligation (608,216) (480,429)
-------- --------
Plan assets in excess of projected
benefit obligation 145,076 221,464
Unrecognized net transition asset (73,612) (80,850)
Unrecognized net (gain) loss (83,709) (139,729)
Unrecognized prior service cost 4,182 5,209
--------- --------
Net pension (liability) asset $(8,063) $ 6,094
========= ========
Plan assets primarily consist of equity securities,
corporate, U.S. agency, and Treasury bonds, and cash equivalents.
The projected benefit obligation was measured using an
assumed discount rate of 7% for 1993 and 7.75% for 1992 and 1991,
and a long-term rate of increase in future compensation levels of
5% for 1993 and 6% for 1992 and 1991. The net pension benefit
was measured using an expected long-term rate of return on plan
assets of 8% in 1993 and 7.5% in 1992 and 1991.
Early Retirement
As part of the corporate restructuring that was announced in
the fourth quarter of 1993 (See Note 6 - Restructuring), the
Company offered a voluntary early retirement program from
December 1, 1993, through January 21, 1994, to employees who were
55 years and older and who had at least 10 years of service with
the Company. The program included two provisions: an unreduced
pension benefit for those eligible employees who were under 60
years old, and a monthly supplemental payment to "bridge"
employees to age 62 when they can begin collecting Social
Security benefits. 384 employees accepted the early retirement
opportunity. In 1993, the Company recorded a $19.9 million
expense for the early retirement program.
Postretirement Benefits Other Than Pensions
The Company has postretirement benefit plans, such as a
comprehensive health insurance plan and a prescription drug plan,
that provide certain benefits for retired employees and their
dependents. Substantially all of the Company's employees who
retire under the Company's pension plan may become eligible for
those benefits at retirement. At December 31, 1993, 1992, and
1991, 1,996, 1,905, and 1,866 retirees and their dependents,
respectively, were covered under these plans. The postretirement
benefit plans are unfunded as of December 31, 1993. However, the
Company is examining the cost-effectiveness of certain funding
alternatives.
In January 1993, the Company adopted Statement of Financial
Accounting Standards No. 106 (SFAS 106), Employers' Accounting
for Postretirement Benefits Other Than Pensions, which requires
that the Company accrue a liability for estimated future
postretirement benefits during an employee's working career
rather than recognize an expense when benefits are paid. At the
time of adoption, the actuarially determined accumulated
postretirement benefit obligation (APBO) was $206.6 million. The
Company elected to recognize the APBO over 20 years.
In September 1993, the PSC issued a Statement of Policy
concerning the accounting and ratemaking treatment for pensions
and postretirement benefits other than pensions (PSC Policy).
The PSC Policy was effective January 1993, adopted SFAS 106 for
accounting and ratemaking purposes, and complies with generally
accepted accounting principles.
Postretirement benefits cost other than pensions that was
recognized on the income statement for the twelve months ended
December 31, 1993, 1992, and 1991, was $11.4 million, $5 million,
and $4.4 million, respectively. The amount for 1993 represents
the portion of SFAS 106 costs that the Company has been allowed
to collect from its customers. The amounts for the twelve months
ended December 31, 1992 and 1991, represent the postretirement
benefits cost as determined prior to the adoption of SFAS 106,
when the cost was not recognized as an expense until the benefits
were paid. The Company has deferred $10.1 million of SFAS 106
costs as of December 31, 1993. The Company expects to recover
any deferred SFAS 106 amounts in accordance with the PSC Policy.
The PSC Policy allows various rate mechanisms, including the
use of excess pension fund assets, such as Internal Revenue
Service Code of 1986 Section 420 transfers, to temper the effect
of SFAS 106 on rates. In 1993, the Company transferred
approximately $5 million of its excess pension plan assets to
cover most of the cost of retirees' health care for that year.
As a result of this transfer, the Company recognized a decrease
in its deferred SFAS 106 asset.
The estimated net postretirement benefits cost other than
pensions for the 12 months ended December 31, 1993, includes the
following components:
(Thousands)
Service cost: Benefits accumulated
during the year $ 6,888
Interest cost on accumulated postretirement
benefit obligation 16,304
Amortization of transition obligation over
20 years 10,330
Deferral for future recovery (22,095)
---------
Net periodic postretirement benefits cost $ 11,427
==========
The status of the plans for postretirements benefits other
than pensions, as reflected in the Company's Consolidated Balance
Sheets at December 31, 1993, is as follows:
(Thousands)
Accumulated postretirement benefit
obligation (APBO):
Retired employees $ 69,947
Fully eligible active plan
participants 36,454
Other active plan employees 107,708
----------
Total APBO 214,109
----------
Less unrecognized transition
obligation 196,268
Less unrecognized net (gain) (10,233)
----------
Accrued postretirement liability $ 28,074
==========
A 12% annual rate of increase in the per capita costs of
covered health care benefits was assumed for 1994, gradually
decreasing to 5% by the year 2003. Increasing the assumed health
care cost trend rates by 1% in each year would increase the APBO
as of January 1, 1994, by $41.5 million and increase the
aggregate of the service cost and interest cost components of the
net postretirement benefits cost for 1994 by $4.6 million. A
discount rate of 7% was used to determine the APBO.
8 Jointly-Owned Generating Stations
Nine Mile Point Unit 2
The Company has an undivided 18% interest in the output and
costs of the Nine Mile Point nuclear generating unit No. 2
(NMP2), which is being operated by Niagara Mohawk Power
Corporation (Niagara Mohawk). Ownership of NMP2 is shared with
Niagara Mohawk 41%, Long Island Lighting Company 18%, Rochester
Gas and Electric Corporation 14%, and Central Hudson Gas &
Electric Corporation 9%. The Company's share of the rated
capability is 189,000 kilowatts. The Company's net utility plant
investment, excluding nuclear fuel, was approximately $652
million and $660 million, at December 31, 1993 and 1992,
respectively. The accumulated provision for depreciation was
approximately $103 million and $90 million, at December 31, 1993
and 1992, respectively. The Company's share of operating
expenses is included in the Consolidated Statements of Income.
A low level radioactive waste management and contingency
plan that has been developed for NMP2 provides assurance that
NMP2 is properly prepared to handle interim storage of low level
radioactive waste until 1998.
Niagara Mohawk has contracted with the U.S. Department of
Energy (DOE) for disposal of high level radioactive waste (spent
fuel) from NMP2. The Company is reimbursing Niagara Mohawk for
its 18% share of the cost under the contract (currently
approximately $1 per megawatt hour of net generation). The DOE's
schedule for start of operations of their high level radioactive
waste repository has slipped from 2003 to no sooner than 2010.
The Company has been advised by Niagara Mohawk that the NMP2
Spent Fuel Storage Pool has a capacity for spent fuel that is
adequate until 2014. If further DOE schedule slippage should
occur, the recent development of pre-licensed dry storage
facilities for use at any nuclear power plant extends the on-site
storage capability for spent fuel at NMP2 beyond 2014.
Nuclear Insurance
Niagara Mohawk maintains public liability and property
insurance for NMP2. The Company reimburses Niagara Mohawk for
its 18% share of those costs.
The public liability limit for a nuclear incident is
approximately $8.8 billion. Should losses stemming from a
nuclear incident exceed the commercially available public
liability insurance, each licensee of a nuclear facility would be
liable for up to a maximum of $75.5 million per incident, payable
at a rate not to exceed $10 million per year. The Company's
maximum liability for its 18% interest in NMP2 would be
approximately $13.6 million per incident. The $75.5 million
assessment is subject to periodic inflation indexing and a 5%
surcharge should funds prove insufficient to pay claims
associated with a nuclear incident. The Price-Anderson Act also
requires indemnification for precautionary evacuations whether or
not a nuclear incident actually occurs.
Niagara Mohawk maintains nuclear property insurance for NMP2
and is reimbursed by the Company for its 18% interest. Niagara
Mohawk has procured property insurance aggregating approximately
$2.7 billion through the Nuclear Insurance Pools and the Nuclear
Electric Insurance Limited (NEIL). In addition, the Company has
purchased NEIL insurance coverage for the extra expense incurred
in purchasing replacement power during prolonged accidental
outages. Under NEIL programs, should losses resulting from an
incident at a member facility exceed the accumulated reserves of
NEIL, each member, including the Company, would be liable for its
share of the deficiency. The Company's maximum liability under
the property damage and replacement power coverages is
approximately $2.3 million.
Nuclear Plant Decommissioning Costs
In May 1993, the Nuclear Regulatory Commission (NRC) updated
labor, energy, and burial cost factors for determining the
minimum funding requirement for nuclear decommissioning. As a
result, the Company's 18% share of the cost to decommission NMP2
is currently estimated to be $234 million in 2027, when
decommissioning is expected to commence ($74 million in 1993
dollars).
The Company's annual decommissioning allowance currently
included in electric rates is approximately $1.6 million and is
sufficient to recover the minimum funding requirement. The
Company believes that any increase in decommissioning costs will
ultimately be recovered in rates.
The Company has established a Qualified Fund under
applicable provisions of the federal tax law. The fund also
complies with the NRC regulations which require the use of an
external trust fund to provide funds to decommission the
contaminated portion of NMP2. The balance in this fund was
approximately $5.7 million and $3.9 million at December 31, 1993
and 1992, respectively, and is included in other property and
investments on the Consolidated Balance Sheets.
Homer City
The Company has an undivided 50% interest in the output and
costs of the Homer City Generating Station, which is comprised of
three generating units. The station is owned with Pennsylvania
Electric Company, which operates the facility. The Company's
share of the rated capability is 954,000 kilowatts and its net
utility plant investment was approximately $258 million and $251
million at December 31, 1993 and 1992, respectively. The
accumulated provision for depreciation was approximately $159
million and $148 million, at December 31, 1993 and 1992,
respectively. The Company's share of operating expenses is
included in the Consolidated Statements of Income.
9 Commitments and Contingencies
Capital Expenditures
The Company has substantial commitments in connection with
its construction program and estimates that capital expenditures
for 1994, 1995, and 1996 will approximate $210 million, $200
million, and $200 million, respectively. These forecasted levels
have been significantly reduced as the Company is taking action
to address competition. The program is subject to periodic
review and revision, and actual construction costs may vary
because of revised load estimates, imposition of additional
regulatory requirements, and the availability and cost of
capital.
Environmental Matters
The Company continually assesses actions that may need to be
taken to ensure compliance with changing environmental laws and
regulations. Compliance programs will increase the cost of
electric and natural gas service by requiring changes to the
Company's operations and facilities. Historically, rate recovery
has been authorized for the cost incurred for compliance with
environmental laws and regulations.
Due to existing and proposed legislation and regulations,
and legal proceedings commenced by governmental bodies and
others, the Company may also incur costs from the past disposal
of hazardous substances produced during the Company's operations
or those of its predecessors. The Company has been notified by
the U. S. Environmental Protection Agency (EPA) and the New York
State Department of Environmental Conservation (NYSDEC) that the
Company is among the potentially responsible parties (PRPs) who
may be liable to pay for costs incurred to remediate certain
hazardous substances at seven waste sites, not including the
Company's inactive gas manufacturing sites, which are discussed
below. With respect to the seven sites, five sites are included
in the New York State Registry of Inactive Hazardous Waste Sites
(New York State Registry).
Any liability may be joint and several for certain of these
sites. The ultimate cost to remediate these sites will be
dependent on such factors as the remedial action plan selected,
the extent of site contamination, and the portion attributed to
the Company. At December 31, 1993, the Company recorded a
liability in the Consolidated Balance Sheets related to four of
these seven sites of $1.8 million. The Company has notified the
NYSDEC that it believes it has no responsibility at two sites and
has already incurred expenditures related to the remediation at
the remaining site. A deferred asset has also been recorded in
the amount of $2.6 million, of which $.8 million relates to costs
that have already been incurred. The Company believes it will
recover these costs, since the PSC has allowed other utilities to
recover these types of remediation costs and has allowed the
Company to recover similar costs in rates, such as investigation
and cleanup costs relating to inactive gas manufacturing sites.
This $1.8 million estimate was derived by multiplying the total
estimated cost to clean up a particular site by the related
Company contribution factor. Estimates of the total cleanup
costs were determined by using information related to a
particular site, such as investigations performed to date at a
site or from the data released by a regulatory agency. In
addition, this estimate was based upon currently available facts,
existing technology, and presently enacted laws and regulations.
The contribution factor is calculated using either the Company's
percentage share of the total PRPs named, which assumes all PRPs
will contribute equally, or the Company's estimated percentage
share of the total hazardous wastes disposed of at a particular
site, or by using a 1% contribution factor for those sites at
which it believes that it has contributed a minimal amount of
hazardous wastes. The Company has notified its former and
current insurance carriers that it seeks to recover from them
certain of these cleanup costs. However, the Company is unable
to predict the amount of insurance recoveries, if any, that it
may obtain.
A number of the Company's inactive gas manufacturing sites
have been listed in the New York State Registry. The Company has
filed petitions to delist the majority of the sites. The
Company's program to investigate and initiate remediation at its
38 known inactive gas manufacturing sites has been extended
through the year 2000. Expenditures over this time period are
estimated to be $25 million. This estimate was determined by
using the Company's experience and knowledge related to these
sites as a result of the investigation and remediation that the
Company has performed to date. It is based upon currently
available facts, existing technology, and presently enacted laws
and regulations. This liability, to investigate and initiate
remediation, as necessary, at the known inactive gas
manufacturing sites, is reflected in the Company's Consolidated
Balance Sheets at December 31, 1993 and 1992. The Company also
has recorded a corresponding deferred asset, since it expects to
recover such expenditures in rates, as the Company has previously
been allowed by the PSC to recover such costs in rates. The
Company has notified its former and current insurance carriers
that it seeks to recover from them certain of these cleanup
costs. However, the Company is unable to predict the amount of
insurance recoveries, if any, that it may obtain.
The Clean Air Act Amendments of 1990 (1990 Amendments) will
result in significant expenditures of approximately $178 million,
on a present value basis, over a 25 year period, for all capital
and operating and maintenance expenses related to the reduction
of sulfur dioxide and nitrogen oxides at several of the Company's
coal-fired generating stations of which $51 million has been
incurred as of December 31, 1993. The Company's current estimate
is a significant reduction from its prior estimate, primarily due
to the postponement of the construction of a flue gas
desulfurization (FGD) system at the Homer City Generating
Station. The Company plans to reevaluate the need to construct
an FGD system at the Homer City Generating Station in 1995, since
its present strategy to bank Phase I emissions allowances for use
during Phase II, as discussed below, will allow the Company to
meet Phase II allowance requirements through the year 2005. The
cost to comply with the sulfur dioxide and nitrogen oxide
limitations includes the construction of an innovative FGD system
and a nitrogen oxide reduction system expected to be completed in
1995 at the Company's Milliken Generating Station. The Company
estimates that approximately a 1% electric rate increase will be
required for the cost of reducing sulfur dioxide and nitrogen
oxide emissions in both Phase I (begins January 1, 1995) and
Phase II (begins January 1, 2000). As a result of the 1990
Amendments, the Company plans to reduce its annual sulfur dioxide
emissions by an amount that will allow the Company to meet the
sulfur dioxide levels established for the Company, which is
approximately a 49% reduction from approximately 138,000 tons in
1989 to 71,000 tons by the year 2000.
The cost of controlling toxic emissions under the 1990
Amendments, if required, cannot be estimated at this time.
Regulations may be adopted at the state level which would limit
toxic emissions even further, at an additional cost to the
Company. The Company anticipates that the costs incurred to
comply with the 1990 Amendments will be recoverable through rates
based on previous rate recovery of required environmental costs.
The 1990 Amendments require the EPA to allocate annual
emissions allowances to each of the Company's coal-fired
generating stations based on statutory emissions limits. An
emissions allowance represents an authorization to emit, during
or after a specified calendar year, one ton of sulfur dioxide.
During Phase I, the Company estimates that it will have
allowances in excess of the affected coal-fired generating
stations' actual emissions. The Company's present strategy is to
bank these allowances for use in later years. By using a banking
strategy, it is estimated that Phase II allowance requirements
will be met through the year 2005 by utilizing the allowances
banked during Phase I, which includes the extension reserve
allowances discussed below, together with the Company's Phase II
annual emissions allowances. This strategy could be modified
should market or business conditions change. In addition to the
annual emissions allowances allocated to the Company by the EPA,
the Company will receive a portion of the extension reserve
allowances issued by the EPA to utilities electing to build
scrubbers, as a result of the pooling agreement that it entered
into with other utilities who were also eligible to receive some
of these extension reserve allowances.
As a result of existing and new solid waste disposal
legislation and regulations in Pennsylvania, the Company will
incur approximately $24 million, on a present value basis, of
additional costs over the next 30 years, beginning in 1994, at
the Homer City Generating Station. These costs will be incurred
to install new equipment, modify or replace existing equipment,
and improve the design of a proposed expansion of disposal
facilities. The Company expects to recover these expenditures in
rates, since the Company has been allowed by the PSC to recover
similar costs in rates, such as groundwater protection costs to
meet permit conditions and regulatory requirements.
Long-term Power Purchase Contracts
The Company has on line and under contract 362 megawatts
(mw) of non-utility generation (NUG) power. In addition, another
240 mw of NUG power is under construction. The Company is
required to make payments under these contracts only for the
power it receives. During 1993, 1992, and 1991 the Company
purchased approximately $138 million, $71 million, and $30
million, respectively, of NUG power. The Company estimates that
it will purchase approximately $255 million, $291 million, and
$335 million of NUG power for the years 1994, 1995, and 1996,
respectively. Increases in NUG power purchase costs are expected
to be a significant contributor to price increases over the next
three years.
As part of the Company's continuing effort to minimize
future price increases associated with uneconomical power
purchases from NUGs, the Company negotiated termination of
agreements for the South Corning and Indeck-Kirkwood cogeneration
projects. The PSC approved full recovery of the $11.5 million in
termination costs for the Indeck-Kirkwood project in rates. The
Company expects to recover the $34 million in termination costs
for the South Corning project in rates because the PSC issued an
order in 1993 allowing the Company to defer these costs and the
Company has been allowed by the PSC to recover costs for the
Indeck-Kirkwood project in rates.
Coal Purchasing Contracts
The Company has long-term contracts with nonaffiliated
mining companies for the purchase of coal for the jointly-owned
Homer City Generating Station. The contracts, which expire
between 1994 and the end of the expected service life of the
generating station, require the purchase of either fixed or
minimum amounts of the station's coal requirements. The price of
the coal under one of these contracts is based on recovery of
production costs plus incentives. The remaining contracts are
based on fixed price plus escalation provisions. The Company's
share of the cost of coal purchased under these agreements is
expected to aggregate $66 million, $45 million, and $31 million
for the years 1994, 1995, and 1996, respectively.
In addition, the Company has a long-term contract for the
purchase of coal for the Kintigh Generating Station. The
contract, which expires in 1997, supplies the annual coal
requirements of the station. One-third of the tonnage price is
renegotiated annually to reflect market conditions. The
delivered cost of coal purchased under this agreement is expected
to be $56 million, $55 million, and $56 million for the years
1994, 1995, and 1996, respectively.
10 Fair Value of Financial Instruments
The estimated fair values of the Company's financial instruments at
December 31, 1993 and 1992, were as follows:
Carrying Amount Fair Value
1993 1992 1993 1992
(Thousands)
First mortgage bonds $1,166,779 $1,318,845 $1,274,883 $1,388,990
Pollution control notes $575,695 $505,680 $581,928 $523,251
Preferred stock subject
to mandatory redemption
requirements $125,000 $108,550 $134,000 $119,031
The carrying amount for the following items approximates
estimated fair value because of the short maturity of those
instruments: cash and cash equivalents, commercial paper, and
interest accrued.
Special deposits include restricted funds that are set aside
for preferred stock and long-term debt redemptions. Special
deposits also include restricted funds that are used to finance a
portion of the costs incurred in the construction of certain
solid waste disposal and other related facilities. The carrying
amount approximates fair value because the special deposits have
been invested in securities with a short-term maturity.
The carrying amount of the revolving credit agreement note
approximates fair value because its pricing is based on short-
term interest rates.
The fair value of the Company's first mortgage bonds,
pollution control notes, and preferred stock is estimated based
on the quoted market prices for the same or similar issues of the
same remaining maturities.
11 Industry Segment Information
Certain information pertaining to the electric and natural gas operations of
the Company is:
1993 1992 1991
Natural Natural Natural
Electric Gas Electric Gas Electric Gas
(Thousands)
Operating
Revenues $1,527,362 $272,787 $1,451,525 $240,164 $1,367,936 $187,879
Expenses $1,250,000 $249,493 $1,146,619 $221,307 $1,056,969 $177,751
Income $277,362 $23,294 $304,906 $18,857 $310,967 $10,128
Depreciation and
amortization* $155,231 $9,337 $150,549 $8,428 $145,700 $6,680
Construction
expenditures $208,576 $36,453 $210,185 $35,433 $210,127 $35,756
Identifiable
assets** $4,615,963 $458,596 $4,540,724 $377,424 $4,515,237 $340,090
* Included in operating expenses.
** Assets used in both electric and natural gas operations not included
above were $201,457, $159,768, and $69,509 at December 31, 1993, 1992, and
1991, respectively. They consist primarily of cash and cash equivalents,
special deposits, and prepayments.
12 Supplementary Income Statement Information
Charges for maintenance, repairs, and depreciation and amortization, are set
forth in the Consolidated Statements of Income. Taxes, other than federal
income taxes, are:
1993 1992 1991
(Thousands)
Property $84,616 $81,640 $76,589
Franchise and gross receipts 92,810 92,153 76,721
Payroll 17,985 17,096 15,467
Miscellaneous 9,551 10,052 9,408
-------- -------- --------
Total Other Taxes $204,962 $200,941 $178,185
======== ======== ========
13 Quarterly Financial Information (Unaudited)
Quarter ended March 31 June 30 Sept. 30 Dec. 31
(Thousands, Except Per Share Amounts)
1993
Operating revenues $522,383 $388,601 $396,410 $492,755
Operating income $109,893 $56,649 $66,108 $68,006
Net income $74,039 $21,500 $32,541 $37,948 (1)
Earnings for common stock $68,838 $16,299 $27,340 $32,913
Earnings per share $.99 $.23 $.39 $.47 (1)
Dividends per share $.54 $.54 $.55 $.55
Average shares outstanding 69,561 69,836 70,119 70,431
Common stock price*
High $35.13 $36.50 $36.25 $35.50
Low $31.63 $32.13 $34.63 $28.75
1992
Operating revenues $489,847 $401,934 $367,833 $432,075
Operating income $111,373 $82,755 $60,109 $69,526
Net income $76,416 $46,772 $26,581 $34,199
Earnings for common stock $71,167 $41,488 $21,320 $28,998
Earnings per share $1.10 (2) $.60 (2) $.31 (2) $.42 (2)
Dividends per share $.53 $.53 $.54 $.54
Average shares outstanding 64,682 68,800 69,063 69,318
Common stock price*
High $29.63 $29.38 $32.00 $32.75
Low $26.13 $26.75 $29.25 $30.38
(1) Fourth quarter 1993 results reflect the effects of restructuring expenses,
which decreased net income and earnings for common stock by $17.2 million
and decreased earnings per share by 24 cents.
(2) Late in 1992, the Company began reflecting on its income statement the
value of energy consumed but not yet billed. If the Company had been
allowed by the PSC to include this unbilled revenue factor during all of
1992, quarterly earnings per share in 1992 would have been 94 cents, 39
cents, 38 cents, and 72 cents for the first, second, third, and fourth
quarters, respectively.
* The Company's common stock is listed on the New York Stock Exchange. The
number of stockholders of record at December 31, 1993 was 58,990.
Dividend Limitations: After dividends on all outstanding preferred stock have
been paid, or declared, and funds set apart for their payment, the common
stock is entitled to cash dividends as may be declared by the Board of
Directors out of retained earnings accumulated since December 31, 1946.
Common Stock dividends are limited if Common Stock Equity (45% at December 31,
1993) falls below 25% of total capitalization, as defined in the Company's
Certificate of Incorporation. Dividends on common stock cannot be paid unless
sinking fund requirements of the preferred stock are met. The Company has not
been restricted in the payment of dividends on common stock by these
provisions. Retained earnings accumulated since December 31, 1946, were
approximately $320 million and $327 million as of December 31, 1993 and 1992,
respectively.
REPORT OF INDEPENDENT ACCOUNTANTS
To the Stockholders and Board of Directors
New York State Electric & Gas Corporation and Subsidiaries
Ithaca, New York
We have audited the consolidated financial statements and the financial
statement schedules of New York State Electric & Gas Corporation and
Subsidiaries listed in Item 14(a) of this Form
10-K. These financial statements and financial statement schedules are the
responsibility of the Company's management. Our responsibility is to express
an opinion on these financial statements and financial statement schedules
based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of New York State
Electric & Gas Corporation and Subsidiaries as of December 31, 1993 and 1992,
and the consolidated results of their operations and their cash flows for each
of the three years in the period ended December 31, 1993, in conformity with
generally accepted accounting principles. In addition, in our opinion, the
financial statement schedules referred to above, when considered in relation
to the basic financial statements taken as a whole, present fairly, in all
material respects, the information required to be included therein.
As discussed in Note 7 to the consolidated financial statements, the Company
and Subsidiaries changed its method of accounting for postretirement benefits
other than pensions in 1993.
COOPERS & LYBRAND
New York, New York
January 28, 1994
NEW YORK STATE ELECTRIC & GAS CORPORATION
Schedule V - Property, Plant, and Equipment
For the Year Ended December 31, 1993
(Thousands of Dollars)
Col. A Col. B Col. C Col. D Col. E Col. F
Balance at Balance at
Beginning of Additions Other End of
Classification Period at Cost (A) Retirements Changes (B) Period
Utility Plant Electric:
Plant in service:
Intangibles $ 1,583 $ - $ - $ - $ 1,583
Production:
Steam 1,725,890 68,155 9,899 2,168 1,786,314
Nuclear 740,437 6,464 5,311 - 741,590
Hydraulic 113,105 1,053 13 - 114,145
Internal combustion 712 2 1 - 713
Nuclear Fuel Assemblies 47,030 7,586 - - 54,616
Transmission 589,747 16,094 3,033 (538) 602,270
Distribution 1,265,035 81,388 11,459 819 1,335,783
General 84,895 22,471 1,851 33,162 (C) 138,677
------------ ----------- ----------- ----------- -------------
Total plant in service 4,568,434 203,213 31,567 35,611 4,775,691
Plant held for future use 5,010 44 - (3,377) 1,677
------------ ----------- ----------- ----------- -------------
4,573,444 203,257 31,567 32,234 4,777,368
Construction work in progress 120,629 (D) (10,872) - - 109,757 (E)
------------ ----------- ----------- ----------- -------------
Total electric 4,694,073 192,385 31,567 32,234 4,887,125
------------ ----------- ----------- ----------- -------------
Utility Plant Gas:
Plant in service:
Intangibles 390 41 - - 431
Production 8,271 79 25 - 8,325
Transmission 10,724 (6) - - 10,718
Distribution 312,454 28,317 1,501 17 339,287
General 5,539 3,121 270 (28) 8,362
------------ ----------- ----------- ----------- -------------
Total plant in service 337,378 31,552 1,796 (11) 367,123
Plant Acquisition Adjustment 14,654 - - (390)(F) 14,264
Plant held for future use 26 (24) - - 2
------------ ----------- ----------- ----------- -------------
352,058 31,528 1,796 (401) 381,389
Construction work in progress 9,571 (D) 2,985 - - 12,556 (E)
------------ ----------- ----------- ----------- -------------
Total gas 361,629 34,513 1,796 (401) 393,945
------------ ----------- ----------- ----------- -------------
Utility Plant Common:
Plant in service:
Intangibles 100 - - - 100
General 157,880 43,951 1,695 (41,250)(C,G) 158,886
------------ ----------- ----------- ----------- -------------
Total plant in service 157,980 43,951 1,695 (41,250) 158,986
Plant held for future use - - - - -
------------ ----------- ----------- ----------- -------------
157,980 43,951 1,695 (41,250) 158,986
Construction work in progress 47,366 (D) (25,820) - - 21,546 (E)
------------ ----------- ----------- ----------- -------------
Total common 205,346 18,131 1,695 (41,250) 180,532
------------ ----------- ----------- ----------- -------------
Total utility plant $ 5,261,048 $ 245,029 $ 35,058 $ (9,417) $ 5,461,602
============ =========== =========== =========== =============
Other physical property (H) $ 73,192 $ 10,771 $ 1,686 $ (1) $ 82,276
============ =========== =========== =========== =============
Notes:
(A) Includes AFDC.
(B) Transfers and Utility Plant Adjustments, except as noted below.
(C) Includes transfer of Energy Control System (ECS) project from Common to Electric construction work
in progress in service not classified of $33,187.
(D) Current year net additions less amounts placed in service included in beginning balance.
(E) Total Construction work in progress, $143,859.
(F) Adjustments related to the acquisition of Columbia Gas of New York, Inc.
(G) Includes Capital Leases - Vehicles and Computer Equipment.
(H) Included in Other Property and Investments, primarily Somerset Railroad Corporation.
NEW YORK STATE ELECTRIC & GAS CORPORATION
Schedule V - Property, Plant, and Equipment
For the Year Ended December 31, 1992
(Thousands of Dollars)
Col. A Col. B Col. C Col. D Col. E Col. F
Balance at Balance at
Beginning of Additions Other End of
Classification Period at Cost (A) Retirements Changes (B) Period
Utility Plant Electric:
Plant in service:
Intangibles $ 1,583 $ - $ - $ - $ 1,583
Production:
Steam 1,705,610 35,386 14,570 (536) 1,725,890
Nuclear 732,860 8,033 456 - 740,437
Hydraulic 105,095 8,262 252 - 113,105
Internal combustion 712 - - - 712
Nuclear Fuel Assemblies 37,116 9,914 - - 47,030
Transmission 571,563 19,456 1,255 (17) 589,747
Distribution 1,194,756 81,468 11,444 255 1,265,035
General 67,596 17,409 75 (35) 84,895
------------ ----------- ----------- ----------- -------------
Total plant in service 4,416,891 179,928 28,052 (333) 4,568,434
Plant held for future use 4,948 (5) - 67 5,010
------------ ----------- ----------- ----------- -------------
4,421,839 179,923 28,052 (266) 4,573,444
Construction work in progress 115,516 (C) 5,113 - - 120,629 (D)
------------ ----------- ----------- ----------- -------------
Total electric 4,537,355 185,036 28,052 (266) 4,694,073
------------ ----------- ----------- ----------- -------------
Utility Plant Gas:
Plant in service:
Intangibles 193 197 - - 390
Production 7,717 554 - - 8,271
Transmission 8,527 2,458 1 (260) 10,724
Distribution 275,821 37,705 1,349 277 312,454
General 4,866 688 3 (12) 5,539
------------ ----------- ----------- ----------- -------------
Total plant in service 297,124 41,602 1,353 5 337,378
Plant Acquisition Adjustment 20,544 - - (5,890)(E) 14,654
Plant held for future use 26 - - - 26
------------ ----------- ----------- ----------- -------------
317,694 41,602 1,353 (5,885) 352,058
Construction work in progress 18,504 (C) (8,933) - - 9,571 (D)
------------ ----------- ----------- ----------- -------------
Total gas 336,198 32,669 1,353 (5,885) 361,629
------------ ----------- ----------- ----------- -------------
Utility Plant Common:
Plant in service:
Intangibles 100 - - - 100
General 156,242 13,342 266 (11,438)(F) 157,880
------------ ----------- ----------- ----------- -------------
Total plant in service 156,342 13,342 266 (11,438) 157,980
Plant held for future use - - - - -
------------ ----------- ----------- ----------- -------------
156,342 13,342 266 (11,438) 157,980
Construction work in progress 32,795 (C) 14,571 - - 47,366 (D)
------------ ----------- ----------- ----------- -------------
Total common 189,137 27,913 266 (11,438) 205,346
------------ ----------- ----------- ----------- -------------
Total utility plant $ 5,062,690 $ 245,618 $ 29,671 $ (17,589) $ 5,261,048
============ =========== =========== =========== =============
Other physical property (G) $ 69,973 $ 117 $ 21 $ 3,123 $ 73,192
============ =========== =========== =========== =============
Notes:
(A) Includes AFDC.
(B) Transfers and Utility Plant Adjustments, except as noted below.
(C) Current year net additions less amounts placed in service included in beginning balance.
(D) Total Construction work in progress, $177,566.
(E) Adjustments related to the acquisition of Columbia Gas of New York, Inc.
(F) Includes Capital Leases - Vehicles and Computer Equipment.
(G) Included in Other Property and Investments, primarily Somerset Railroad Corporation.
NEW YORK STATE ELECTRIC & GAS CORPORATION
Schedule V - Property, Plant, and Equipment
For the Year Ended December 31, 1991
(Thousands of Dollars)
Col. A Col. B Col. C Col. D Col. E Col. F
Balance at Balance at
Beginning of Additions Other End of
Classification Period at Cost (A) Retirements Changes (B) Period
Utility Plant Electric:
Plant in service:
Intangibles $ 1,583 $ - $ - $ - $ 1,583
Production:
Steam 1,687,918 29,092 4,754 (6,646)(C) 1,705,610
Nuclear 731,657 1,220 17 - 732,860
Hydraulic 104,559 565 29 - 105,095
Internal combustion 712 - - - 712
Nuclear Fuel Assemblies 27,918 9,198 - - 37,116
Transmission 545,547 26,673 1,099 442 571,563
Distribution 1,130,047 75,259 10,711 161 1,194,756
General 43,968 25,245 1,245 (372) 67,596
------------ ----------- ----------- ----------- -------------
Total plant in service 4,273,909 167,252 17,855 (6,415) 4,416,891
Plant held for future use 6,016 - - (1,068) 4,948
------------ ----------- ----------- ----------- -------------
4,279,925 167,252 17,855 (7,483) 4,421,839
Construction work in progress 87,989 (D) 27,527 - - 115,516 (E)
------------ ----------- ----------- ----------- -------------
Total electric 4,367,914 194,779 17,855 (7,483) 4,537,355
------------ ----------- ----------- ----------- -------------
Utility Plant Gas:
Plant in service:
Intangibles 51 113 - 29 (F) 193
Production 4,727 71 - 2,919 (F) 7,717
Transmission 8,503 124 8 (92)(F) 8,527
Distribution 197,956 23,538 1,004 55,331 (F) 275,821
General 2,703 158 117 2,122 (F) 4,866
------------ ----------- ----------- ----------- -------------
Total plant in service 213,940 24,004 1,129 60,309 297,124
Plant Acquisition Adjustment - - - 20,544 (F) 20,544
Plant held for future use 24 2 - - 26
------------ ----------- ----------- ----------- -------------
213,964 24,006 1,129 80,853 317,694
Construction work in progress 8,160 (D) 10,344 - - 18,504 (E)
------------ ----------- ----------- ----------- -------------
Total gas 222,124 34,350 1,129 80,853 336,198
------------ ----------- ----------- ----------- -------------
Utility Plant Common:
Plant in service:
Intangibles 100 - - - 100
General 145,711 13,851 1,733 (1,587)(G) 156,242
------------ ----------- ----------- ----------- -------------
Total plant in service 145,811 13,851 1,733 (1,587) 156,342
Plant held for future use - - - - -
------------ ----------- ----------- ----------- -------------
145,811 13,851 1,733 (1,587) 156,342
Construction work in progress 29,892 (D) 2,903 - - 32,795 (E)
------------ ----------- ----------- ----------- -------------
Total common 175,703 16,754 1,733 (1,587) 189,137
------------ ----------- ----------- ----------- -------------
Total utility plant $ 4,765,741 $ 245,883 $ 20,717 $ 71,783 $ 5,062,690
============ =========== =========== =========== =============
Other physical property (H) $ 69,913 $ 373 $ 470 $ 157 $ 69,973
============ =========== =========== =========== =============
Notes:
(A) Includes AFDC.
(B) Transfers and Utility Plant Adjustments, except as noted below.
(C) Primarily the write-off of a portion of the disallowed Homer City Coal Cleaning Plant.
(D) Current year net additions less amounts placed in service included in beginning balance.
(E) Total Construction work in progress, $166,815.
(F) Adjustments related to the acquisition of Columbia Gas of New York, Inc.
(G) Includes Capital Leases - Vehicles and Computer Equipment.
(H) Included in Other Property and Investments, primarily Somerset Railroad Corporation.
NEW YORK STATE ELECTRIC & GAS CORPORATION
Schedule VI - Accumulated Depreciation of Property, Plant, and Equipment
For the Year Ended December 31, 1993
(Thousands of Dollars)
Col. A Col. B Col. C Col. D Col. E Col. F
Balance at Additions Balance at
Beginning Charged End
of to Costs Other of
Description Period and Expenses Retirements Changes (A) Period
Utility Plant Electric:
Plant in service:
Intangibles $ 407 $ 49 $ - $ - $ 456
Production:
Steam 550,539 65,074 13,927 (7,682)(B) 594,004
Nuclear 93,510 25,988 5,329 (5,131) 109,038
Hydraulic 17,945 2,143 53 - 20,035
Internal combustion 720 28 4 - 744
Nuclear Fuel Assemblies 33,158 - - 5,703 (C) 38,861
Transmission 196,728 12,890 17,096 156 192,678
Distribution 382,086 43,705 3,068 (156) 422,567
General 20,696 2,059 3,295 2,193 (D,E) 21,653
------------ ------------ ----------- ---------- -------------
Total plant in service 1,295,789 151,936 42,772 (4,917) 1,400,036
Plant held for future use 1,075 - 1,073 - 2
------------ ------------ ----------- ---------- -------------
Total electric 1,296,864 151,936 43,845 (4,917) 1,400,038
------------ ------------ ----------- ---------- -------------
Utility Plant Gas:
Plant in service:
Production 5,407 247 56 - 5,598
Transmission 3,933 415 769 - 3,579
Distribution 84,792 7,798 1,292 287 91,585
General 3,095 254 341 137 (D,E) 3,145
------------ ------------ ----------- ---------- -------------
Total gas 97,227 8,714 2,458 424 103,907
------------ ------------ ----------- ---------- -------------
Utility Plant Common:
Plant in service - general 33,702 3,918 1,427 1,318 (D) 37,511
------------ ------------ ----------- ---------- -------------
Total accumulated depreciation
of utility plant $ 1,427,793 $ 164,568(C) $ 47,730 $ (3,175) $ 1,541,456
============ ============ =========== ========== =============
Accumulated depreciation of
other physical property (F) $ 19,320 $ 2,962(G) $ 794 $ 360 $ 21,848
============ ============ =========== ========== =============
Notes:
(A) Transfers, except as noted below.
(B) Includes Somerset Non-Cash Return of $7,317 and $209 related to power plant asbestos removal.
(C) The amortization of nuclear fuel assemblies is classified as fuel expense on the Company's
Consolidated Statements of Income.
(D) Primarily provision for depreciation of automotive equipment, tools and work equipment charged
initially to clearing accounts and subsequently distributed to operating expense and construction
accounts.
(E) Distributed to deferred debits.
(F) Included in Other Property and Investments, primarily Somerset Railroad Corporation.
(G) Charged to non-operating income.
NEW YORK STATE ELECTRIC & GAS CORPORATION
Schedule VI - Accumulated Depreciation of Property, Plant, and Equipment
For the Year Ended December 31, 1992
(Thousands of Dollars)
Col. A Col. B Col. C Col. D Col. E Col. F
Balance at Additions Balance at
Beginning Charged End
of to Costs Other of
Description Period and Expenses Retirements Changes (A) Period
Utility Plant Electric:
Plant in service:
Intangibles $ 358 $ 49 $ - $ - $ 407
Production:
Steam 507,896 64,197 14,128 (7,426)(B) 550,539
Nuclear 73,681 25,374 968 (4,577) 93,510
Hydraulic 16,247 2,128 430 - 17,945
Internal combustion 693 27 - - 720
Nuclear Fuel Assemblies 28,921 - - 4,237 (C) 33,158
Transmission 185,214 13,218 1,725 21 196,728
Distribution 357,227 40,708 15,818 (31) 382,086
General 17,913 1,926 464 1,321 (D,E) 20,696
------------ ------------ ----------- ---------- -------------
Total plant in service 1,188,150 147,627 33,533 (6,455) 1,295,789
Plant held for future use 1,075 - - - 1,075
------------ ------------ ----------- ---------- -------------
Total electric 1,189,225 147,627 33,533 (6,455) 1,296,864
------------ ------------ ----------- ---------- -------------
Utility Plant Gas:
Plant in service:
Production 5,169 238 - - 5,407
Transmission 3,589 223 10 131 3,933
Distribution 79,264 7,224 1,771 75 84,792
General 2,769 217 6 115 (D,E) 3,095
------------ ------------ ----------- ---------- -------------
Total gas 90,791 7,902 1,787 321 97,227
------------ ------------ ----------- ---------- -------------
Utility Plant Common:
Plant in service - general 29,813 3,448 724 1,165 (D) 33,702
------------ ------------ ----------- ---------- -------------
Total accumulated depreciation
of utility plant $ 1,309,829 $ 158,977(C) $ 36,044 $ (4,969) $ 1,427,793
============ ============ =========== ========== =============
Accumulated depreciation of
other physical property (F) $ 16,555 $ 2,421(G) $ (32) $ 312 $ 19,320
============ ============ =========== ========== =============
Notes:
(A) Transfers, except as noted below.
(B) Includes Somerset Non-Cash Return of $7,317 and $105 related to power plant asbestos removal.
(C) The amortization of nuclear fuel assemblies is classified as fuel expense on the Company's
Consolidated Statements of Income.
(D) Primarily provision for depreciation of automotive equipment, tools and work equipment charged
initially to clearing accounts and subsequently distributed to operating expense and construction
accounts.
(E) Distributed to deferred debits.
(F) Included in Other Property and Investments, primarily Somerset Railroad Corporation.
(G) Charged to non-operating income.
NEW YORK STATE ELECTRIC & GAS CORPORATION
Schedule VI - Accumulated Depreciation of Property, Plant, and Equipment
For the Year Ended December 31, 1991
(Thousands of Dollars)
Col. A Col. B Col. C Col. D Col. E Col. F
Balance at Additions Balance at
Beginning Charged End
of to Costs Other of
Description Period and Expenses Retirements Changes (A) Period
Utility Plant Electric:
Plant in service:
Intangibles $ 311 $ 47 $ - $ - $ 358
Production:
Steam 466,294 63,300 12,773 (8,925)(B) 507,896
Nuclear 50,434 24,989 (2,621) (4,363) 73,681
Hydraulic 14,769 1,952 474 - 16,247
Internal combustion 665 28 - - 693
Nuclear Fuel Assemblies 23,042 - - 5,879 (C) 28,921
Transmission 173,032 13,355 1,149 (24) 185,214
Distribution 333,754 37,927 14,478 24 357,227
General 16,779 1,268 962 828 (D,E) 17,913
------------ ------------ ----------- ---------- -------------
Total plant in service 1,079,080 142,866 27,215 (6,581) 1,188,150
Plant held for future use 1,075 - - - 1,075
------------ ------------ ----------- ---------- -------------
Total electric 1,080,155 142,866 27,215 (6,581) 1,189,225
------------ ------------ ----------- ---------- -------------
Utility Plant Gas:
Plant in service:
Production 3,486 209 - 1,474 (F) 5,169
Transmission 3,129 152 (257) 51 (F) 3,589
Distribution 59,960 5,856 1,169 14,617 (F) 79,264
General 945 167 (133) 1,524 (D,E,F) 2,769
------------ ------------ ----------- ---------- -------------
Total gas 67,520 6,384 779 17,666 90,791
------------ ------------ ----------- ---------- -------------
Utility Plant Common:
Plant in service - general 26,976 3,130 938 645 (D) 29,813
------------ ------------ ----------- ---------- -------------
Total accumulated depreciation
of utility plant $ 1,174,651 $ 152,380(C) $ 28,932 $ 11,730 $ 1,309,829
============ ============ =========== ========== =============
Accumulated depreciation of
other physical property (G) $ 14,271 $ 2,296(H) $ (155) $ (167) $ 16,555
============ ============ =========== ========== =============
Notes:
(A) Transfers, except as noted below.
(B) Includes Somerset Non-Cash Return of $7,317 and $1,608 related to the Homer City Coal Cleaning
Plant Write-off.
(C) The amortization of nuclear fuel assemblies is classified as fuel expense on the Company's
Consolidated Statements of Income.
(D) Primarily provision for depreciation of automotive equipment, tools and work equipment charged
initially to clearing accounts and subsequently distributed to operating expense and construction
accounts.
(E) Distributed to deferred debits.
(F) Includes adjustments related to the acquisition of Columbia Gas of New York, Inc.
(G) Included in Other Property and Investments, primarily Somerset Railroad Corporation.
(H) Charged to non-operating income.
NEW YORK STATE ELECTRIC & GAS CORPORATION
SCHEDULE VIII - ALLOWANCE FOR DOUBTFUL ACCOUNTS - ACCOUNTS RECEIVABLE
(Thousands of Dollars)
Beginning End
Year of Year Additions Write-offs (a) Adjustments of Year (c)
1993 $1,900 $15,306 $(13,206) $4,000
1992 700 11,518 (10,318) 1,900
1991 300 10,719 (10,673) $354 (b) 700
(a) Uncollectible accounts charged against the allowance, net of recoveries.
(b) Due to the acquisition of Columbia Gas of New York, Inc., in April 1991.
(c) Represents an estimate of the write-offs that will not be recovered in rates.
Item 9. Changes in and disagreements with accountants on accounting and
financial disclosure - None
PART III
Item 10. Directors and executive officers of the Registrant
Incorporated herein by reference to the information under the caption
"Election of Directors" in the Company's Proxy Statement dated March 31, 1994.
The information regarding executive officers is on pages 23-25 of this report.
Item 11. Executive compensation
Incorporated herein by reference to the information under the captions
"Executive Compensation," "Employment and Change in Control Arrangements,"
"Directors' Compensation," "Compensation Committee Interlocks and Insider
Participation," "Report of Executive Compensation and Succession Committee on
Executive Compensation" and "Stock Performance Graph" in the Company's Proxy
Statement dated March 31, 1994.
Item 12. Security ownership of certain beneficial owners and management
Incorporated herein by reference to the information under the caption
"Security Ownership of Certain Beneficial Owners and Management" in the
Company's Proxy Statement dated March 31, 1994.
Item 13. Certain relationships and related transactions
Incorporated herein by reference to the information under the captions
"Election of Directors" and "Employment and Change in Control Arrangements" in
the Company's Proxy Statement dated March 31, 1994.
PART IV
Item 14. Exhibits, financial statement schedules, and reports on Form 8-K
(a) The following documents are filed as part of this report:
1. Financial statements
Included in Part II of this report:
a) Consolidated Statements of Income for the three years
ended December 31, 1993
b) Consolidated Balance Sheets as of December 31, 1993 and 1992
c) For the three years ended December 31, 1993:
Consolidated Statements of Cash Flows
Consolidated Statements of Changes in Common Stock Equity
d) Notes to Consolidated Financial Statements
e) Report of Independent Accountants
2. Financial statement schedules
Included in Part II of this report:
For the three years ended December 31, 1993:
V. Property, Plant and Equipment
VI. Accumulated Depreciation of Property, Plant and Equipment
VIII. Allowance for Doubtful Accounts - Accounts Receivable
Schedules other than those listed above have been omitted since they are
not required, are inapplicable or the required information is presented in the
Consolidated Financial Statements or notes thereto.
3. Exhibits
(a)(1) The following exhibits are delivered with this report:
Exhibit No.
3-11 - Certificate of Amendment of the Certificate of Incorporation filed
in the Office of the Secretary of State of the State of New
York on December 10, 1993.
3-12 - Certificate of Amendment of the Certificate of Incorporation filed
in the Office of the Secretary of State of the State of New
York on December 20, 1993.
3-13 - Certificate of Amendment of the Certificate of Incorporation filed
in the Office of the Secretary of State of the State of New
York on December 20, 1993.
3-15 - By-Laws of the Company as amended February 25, 1994.
10-14 - Coal Sales Agreement dated December 21, 1983 between New York
State Electric & Gas Corporation and Consolidation Coal Company.
(A) 10-21 - Retirement Plan for Directors Amendment No. 1.
(A) 10-23 - Deferred Compensation Plan for Directors Amendment No. 1.
(A) 10-32 - Supplemental Executive Retirement Plan Amendment No. 8.
(A) 10-33 - Supplemental Executive Retirement Plan Amendment No. 9.
(A) 10-35 - Annual Executive Incentive Compensation Plan Amendment No. 1.
(A) 10-36 - Annual Executive Incentive Compensation Plan Amendment No. 2.
(A) 10-41 - Performance Share Plan Amendment No. 4.
(A) 10-43 - Performance Share Deferred Compensation Plan Amendment No. 1.
(A) 10-46 - Employment Agreement for J. A. Carrigg.
(A) 10-47 - Form of Severance Agreement for Senior Vice Presidents.
(A) 10-48 - Form of Severance Agreement for Vice Presidents.
12 - Computation of Ratio of Earnings to Fixed Charges.
21 - Subsidiaries.
23 - Consent of Coopers & Lybrand to incorporation by reference into
certain registration statements.
99-1 - Form 11-K for New York State Electric & Gas Corporation Tax
Deferred Savings Plan for Salaried Employees.
99-2 - Form 11-K for New York State Electric & Gas Corporation Tax
Deferred Savings Plan for Hourly Paid Employees.
(a)(2) The following exhibits are incorporated herein by reference:
Exhibit No. Filed in As Exhibit No.
3-1 - Restated Certificate of Incorporation of the
Company pursuant to Section 807 of the Business
Corporation Law filed in the Office of the
Secretary of State of the State of New York on
October 25, 1988 - Registration No. 33-50719 . . . 4-11
3-2 - Certificate of Amendment of the Certificate of
Incorporation filed in the Office of the
Secretary of State of the State of New York
on October 17, 1989 - Registration No. 33-50719 . . 4-12
3-3 - Certificate of Amendment of the Certificate of
Incorporation filed in the Office of the Secretary
of State of the State of New York on May 22, 1990 -
Registration No. 33-50719 . . . . . . . . . . . . . 4-13
3-4 - Certificate of Amendment of the Certificate of
Incorporation filed in the Office of the
Secretary of State of the State of New York
on October 31, 1990 - Registration No. 33-50719 . . 4-14
______________________________
(A) Management contract or compensatory plan or arrangement.
Exhibit No. Filed in As Exhibit No.
3-5 - Certificate of Amendment of the Certificate of
Incorporation filed in the Office of the
Secretary of State of the State of New York
on February 6, 1991 - Registration No. 33-50719 . . 4-15
3-6 - Certificate of Amendment of the Certificate of
Incorporation filed in the Office of the
Secretary of State of the State of New York
on October 15, 1991 - Registration No. 33-50719 . . 4-16
3-7 - Certificate of Merger of Columbia Gas of
New York, Inc. into the Company filed in the
Office of the Secretary of State of the State
of New York on April 8, 1991 - Registration
No. 33-50719 . . . . . . . . . . . . . . . . . . . 4-20
3-8 - Certificate of Amendment of the Certificate of
Incorporation filed in the Office of the Secretary
of State of the State of New York
on May 28, 1992 - Registration No. 33-50719 . . . . 4-17
3-9 - Certificate of Amendment of the Certificate of
Incorporation filed in the Office of the Secretary
of State of the State of New York
on October 20, 1992 - Registration No. 33-50719 . . . 4-18
3-10 - Certificate of Amendment of the Certificate of
Incorporation filed in the Office of the Secretary
of State of the State of New York on October 14, 1993
Registration No. 33-50719 . . . . . . . . . . . . . . 4-19
3-14 - Certificates of the Secretary of the Company concern-
ing consents dated March 20, 1957 and May 9, 1975 of
holders of Serial Preferred Stock with respect to
issuance of certain unsecured indebtedness -
Registration No. 2-69988. . . . . . . . . . . . . . 4-7
4-1 - First Mortgage dated as of July 1, 1921 executed by
the Company under its then name of "New York State
Gas and Electric Corporation" to The Equitable Trust
Company of New York, as Trustee (Chemical Bank is
Successor Trustee) - Registration No. 33-4186 . . . 4-1
Supplemental Indentures to First Mortgage dated as of July 1, 1921:
4-2 - No. 37 - Registration No. 33-31297. . . . . . . . . 4-2
4-3 - No. 39 - Registration No. 33-31297. . . . . . . . . 4-3
4-4 - No. 43 - Registration No. 33-31297. . . . . . . . . 4-4
4-5 - No. 51 - Registration No. 2-59840 . . . . . . . . . 2-B(46)
4-6 - No. 68 - Registration No. 2-59840 . . . . . . . . . 2-B(63)
4-7 - No. 69 - Registration No. 2-59840 . . . . . . . . . 2-B(64)
4-8 - No. 71 - Registration No. 2-59840 . . . . . . . . . 2-B(66)
4-9 - No. 74 - Registration No. 2-59840 . . . . . . . . . 2-B(69)
4-10 - No. 75 - Registration No. 2-59840 . . . . . . . . . 2-B(70)
4-11 - No. 80 - Registration No. 2-59840 . . . . . . . . . 2-B(75)
4-12 - No. 81 - Registration No. 2-59840 . . . . . . . . . 2-B(76)
4-13 - No. 83 - Registration No. 2-65948 . . . . . . . . . 2-B(78)
4-14 - No. 99 - Registration No. 33-11303. . . . . . . . . 4-9
4-15 - No. 102- Registration No. 33-33838. . . . . . . . . 4-8
4-16 - No. 103- Registration No. 33-43458. . . . . . . . . 4-8
4-17 - No. 104- Registration No. 33-43458. . . . . . . . . 4-9
4-18 - No. 105- Registration No. 33-52040. . . . . . . . . 4-8
4-19 - No. 106- Company's 10-K for year ended
December 31, 1992 - File No. 1-3103-2. . . 4-23
4-20 - No. 107- Company's 10-K for year ended
December 31, 1992 - File No. 1-3103-2. . . 4-24
4-21 - No. 108- Registration No. 33-50719. . . . . . . . . 4-8
4-22 - No. 109- Registration No. 33-50719. . . . . . . . . 4-9
Contracts, amendments, and letter agreement with the Power Authority of
the State of New York:
10-1 - Contract UD-4 dated July 28, 1975 (FitzPatrick
Power) - Registration No. 2-59840 . . . . . . . . . 5-5
Exhibit No. Filed in As Exhibit No.
10-2 - Contract PS-2 dated March 28, 1973 (Blenheim-
Gilboa) - Registration No. 2-59840. . . . . . . . . 5-6
10-3 - Letter Agreement dated February 3, 1982 relating to
transmission services - Registration No. 2-82192. . 10-1
10-4 - Amendment dated December 21, 1989 to the Letter
Agreement dated February 3, 1982 relating to trans-
mission services - Company's 10-K for year ended
December 31, 1989 - File No. 1-3103-2 . . . . . . 10-4
10-5 - Contract effective as of February 22, 1989 relating
to the purchase of hydroelectric power - Company's
10-K for year ended December 31, 1988 - File No.
1-3103-2. . . . . . . . . . . . . . . . . . . . . . 10-5
10-6 - Transmission Agreement dated December 12, 1983,
with respect to connection of the Company's Kintigh
(Somerset) Generating Station to the Niagara-Edic
345 kv transmission system - Company's 10-K for year
ended December 31, 1988 - File No. 1-3103-2 . . . . 10-6
10-7 - Amendment dated December 21, 1989 to the Transmission
Agreement dated December 12, 1983 with respect to
connection of the Company's Kintigh (Somerset) Gener-
ating Station to the Niagara-Edic 345 kv transmission
system - Company's 10-K for the year ended December
31, 1989 File No. 1-3103-2. . . . . . . . . . . . . 10-7
Coal Sales Agreements and Amendments between New York State Electric & Gas
Corporation, Pennsylvania Electric Company and:
10-8 - Helvetia Coal Company - Agreement made as of
December 22, 1966 - Registration No. 2-59840. . . . 5-11
10-9 - Helvetia Coal Company - Amendment made as of
April 1, 1974 - Registration No. 2-55131. . . . . . 5-F(1)b
10-10 - Amendment dated as of March 15, 1989 to the Coal
Sales Agreement made as of December 22, 1966 between
New York State Electric & Gas Corporation, Penn-
sylvania Electric Company and Helvetia Coal Company -
Company's 10-K for year ended December 31, 1990 -
File No. 1-3103-2 . . . . . . . . . . . . . . . . 10-10
10-11 - Amendment dated as of July 25, 1990 to the Coal
Sales Agreement made as of December 22, 1966 between
New York State Electric & Gas Corporation, Penn-
sylvania Electric Company and Helvetia Coal Company -
Company's 10-K for year ended December 31, 1990 -
File No. 1-3103-2 . . . . . . . . . . . . . . . . 10-11
* * * * * * * * * *
Exhibit No. Filed in As Exhibit No.
10-12 - New York Power Pool Agreement dated July 11, 1985 -
Company's 10-K for year ended December 31, 1988 -
File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-7
10-13 - Transmission Agreement dated January 10, 1990 between
New York State Electric & Gas Corporation and Niagara
Mohawk Power Corporation, with respect to remote load
and generation wheeling service for the Company -
Company's 10-K for year ended December 31, 1990 -
File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-17
10-15 - Amendment No. 1 dated as of October 1, 1985 to the
Coal Sales Agreement dated December 21, 1983 between
the Company and Consolidation Coal Company -
Company's 10-K for year ended December 31, 1986 -
File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-11
10-16 - Amendment No. 2 dated as of August 28, 1986 to the
Coal Sales Agreement dated December 21, 1983 between
the Company and Consolidation Coal Company -
Company's 10-K for year ended December 31, 1986 -
File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-12
10-17 - Basic Agreement dated as of September 22, 1975
between New York State Electric & Gas Corporation
and others concerning Nine Mile Point Nuclear
Station, Unit No. 2 - Registration No. 2-54903. . . 5-0
10-18 - Nine Mile Point Nuclear Station Unit 2 Operating
Agreement effective as of January 1, 1993 among
New York State Electric & Gas Corporation and
others - Company's 10-K for the year ended
December 31, 1992 - File No. 1-3103-2 . . . . . . . 10-18
10-19 - Coal Hauling Agreement dated as of March 9, 1983
between Somerset Railroad Corporation and New
York State Electric & Gas Corporation -
Registration No. 2-82352. . . . . . . . . . . . . . 10
(A) 10-20 - Retirement Plan for Directors - Company's 10-K
for the year ended December 31, 1991 -
File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-26
(A) 10-22 - Form of Deferred Compensation Plan for Directors -
Company's 10-K for year ended December 31, 1989 -
File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-22
(A) 10-24 - Supplemental Executive Retirement Plan - Company's
10-Q for quarter ended September 30, 1984 -
File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-19
(A) 10-25 - Supplemental Executive Retirement Plan Amendment
No. 1 - Company's 10-Q for quarter ended
March 31, 1985 - File No. 1-3103-2. . . . . . . . . 10-21
______________________________
(A) Management contract or compensatory plan or arrangement.
Exhibit No. Filed in As Exhibit No.
(A) 10-26 - Supplemental Executive Retirement Plan Amendment
No. 2 - Company's 10-K for year ended December
31, 1987 - File No. 1-3103-2. . . . . . . . . . . . 10-19
(A) 10-27 - Supplemental Executive Retirement Plan Amendment
No. 3 - Company's 10-K for year ended December 31,
1988 - File No. 1-3103-2. . . . . . . . . . . . . . 10-24
(A) 10-28 - Supplemental Executive Retirement Plan Amendment
No. 4 - Company's 10-K for year ended December 31,
1990 - File No. 1-3103-2. . . . . . . . . . . . . . 10-30
(A) 10-29 - Supplemental Executive Retirement Plan Amendment
No. 5 - Company's 10-K for year ended December 31,
1990 - File No. 1-3103-2. . . . . . . . . . . . . . 10-31
(A) 10-30 - Supplemental Executive Retirement Plan Amendment
No. 6 - Company's 10-Q for quarter ended March 31,
1991 - File No. 1-3103-2. . . . . . . . . . . . . . 10-37
(A) 10-31 - Supplemental Executive Retirement Plan Amendment
No. 7 - Company's 10-Q for quarter ended June 30,
1992 - File No. 1-3103-2. . . . . . . . . . . . . . 10-44
(A) 10-34 - Annual Executive Incentive Compensation Plan.
Company's 10-K for year ended December 31, 1992 -
File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-30
(A) 10-37 - Performance Share Plan - Company's 10-K for year
ended December 31, 1990 - File No. 1-3103-2 . . . . 10-36
(A) 10-38 - Performance Share Plan Amendment No. 1 - Company's
10-Q for quarter ended March 31, 1991 -
File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-38
(A) 10-39 - Performance Share Plan Amendment No. 2 - Company's
10-Q for quarter ended June 30, 1991 -
File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-39
(A) 10-40 - Performance Share Plan Amendment No. 3 - Company's
10-K for year ended December 31, 1992 - File No.
1-3103-2. . . . . . . . . . . . . . . . . . . . . . 10-34
(A) 10-42 - Performance Share Deferred Compensation Plan -
Company's 10-K for year ended December 31, 1991
File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-40
(A) 10-44 - Employment Contract for A. E. Kintigh - Company's
10-K for year ended December 31, 1988 - File
No. 1-3103-2. . . . . . . . . . . . . . . . . . . . 10-26
(A) 10-45 - Agreement with R. Fleming, Jr. - Company's 10-K for
year ended December 31, 1990 - File No. 1-3103-2. . 10-34
The Company agrees to furnish to the Commission, upon request, a copy of
the Revolving Credit Agreement dated as of July 31, 1992, between the Company,
Chemical Bank, as Agent, and certain banks; a copy of the Participation
Agreement dated as of February 1, 1984 between the Company and New York State
Energy Research and Development Authority (NYSERDA) relating to Pollution
Control Revenue Bonds; a copy of the Participation Agreements dated as of
October 15, 1984, June 1, 1987 and December 1, 1988 between the Company and
NYSERDA relating to Adjustable Rate Pollution Control Revenue Bonds (1984
Series A), (1987 Series A), and (1988 Series A), respectively; a copy of the
Participation Agreements dated as of March 1, 1985, October 15, 1985, July 15,
1985 and December 1, 1985 between the Company and NYSERDA relating to Annual
______________________________
(A) Management contract or compensatory plan or arrangement.
Tender Pollution Control Revenue Bonds (1985 Series A), (1985 Series B), (1985
Series C) and (1985 Series D), respectively; a copy of the Participation
Agreements dated as of February 1, 1993 and February 1, 1994 between the
Company and NYSERDA relating to Pollution Control Refunding Revenue Bonds (1994
Series A) and (1994 Series B) respectively; a copy of the Participation
Agreement dated as of December 1, 1993 between the Company and NYSERDA relating
to Solid Waste Disposal Revenue Bonds (1993 Series A); and a copy of the Credit
Agreement dated as of March 9, 1983, as amended, between Somerset Railroad
Corporation and Chemical Bank. The total amount of securities authorized under
each of such agreements does not exceed 10% of the total assets of the Company
and its subsidiaries on a consolidated basis.
(b) Reports on Form 8-K
A report on Form 8-K, dated November 29, 1993, was filed during the
fourth quarter of 1993 to report certain information under Item 5, "Other
Events."
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
NEW YORK STATE ELECTRIC & GAS CORPORATION
Date: March 11, 1994 By Everett A. Robinson
Everett A. Robinson
Vice President and Controller
(Chief Accounting Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
PRINCIPAL EXECUTIVE OFFICER
Date: March 11, 1994 By James A. Carrigg
James A. Carrigg
Chairman, President,
Chief Executive Officer and
Director
PRINCIPAL FINANCIAL OFFICER
Date: March 11, 1994 By Sherwood J. Rafferty
Sherwood J. Rafferty
Vice President and Treasurer
PRINCIPAL ACCOUNTING OFFICER
Date: March 11, 1994 By Everett A. Robinson
Everett A. Robinson
Vice President and Controller
Signatures (Cont'd)
Date: March 11, 1994 By Alison P. Casarett
Alison P. Casarett
Director
Date: March 11, 1994 By Everett A. Gilmour
Everett A. Gilmour
Director
Date: March 11, 1994 By Paul L. Gioia
Paul L. Gioia
Director
Date: March 11, 1994 By John M. Keeler
John M. Keeler
Director
Date: March 11, 1994 By Allen E. Kintigh
Allen E. Kintigh
Director
Date: March 11, 1994 By Ben E. Lynch
Ben E. Lynch
Director
Date: March 11, 1994 By Alton G. Marshall
Alton G. Marshall
Director
Date: March 11, 1994 By David R. Newcomb
David R. Newcomb
Director
Date: March 11, 1994 By Robert A. Plane
Robert A. Plane
Director
Date: March 11, 1994 By C. William Stuart
C. William Stuart
Director
EXHIBIT INDEX
* 3-1 -- Restated Certificate of Incorporation of the
Company pursuant to Section 807 of the Business
Corporation Law filed in the Office of the
Secretary of State of the State of New York on
October 25, 1988.
* 3-2 -- Certificate of Amendment of the Certificate of
Incorporation filed in the Office of the
Secretary of State of the State of New York on
October 17, 1989.
* 3-3 -- Certificate of Amendment of the Certificate of
Incorporation filed in the Office of the
Secretary of State of the State of New York on
May 22, 1990.
* 3-4 -- Certificate of Amendment of the Certificate of
Incorporation filed in the Office of the
Secretary of State of the State of New York on
October 31, 1990.
* 3-5 -- Certificate of Amendment of the Certificate of
Incorporation filed in the Office of the
Secretary of State of the State of New York on
February 6, 1991.
* 3-6 -- Certificate of Amendment of the Certificate of
Incorporation filed in the Office of the
Secretary of State of the State of New York on
October 15, 1991.
* 3-7 -- Certificate of Merger of Columbia Gas of New
York, Inc. into the Company filed in the Office
of the Secretary of State of the State of New
York on April 8, 1991.
* 3-8 -- Certificate of Amendment of the Certificate of
Incorporation filed in the Office of the
Secretary of State of the State of New York on
May 28, 1992.
* 3-9 -- Certificate of Amendment of the Certificate of
Incorporation filed in the Office of the
Secretary of State of the State of New York on
October 20, 1992.
* 3-10 -- Certificate of Amendment of the Certificate of
Incorporation filed in the Office of the
Secretary of State of the State of New York on
October 14, 1993.
3-11 -- Certificate of Amendment of the Certificate of
Incorporation filed in the Office of the
Secretary of State of the State of New York on
December 10, 1993.
3-12 -- Certificate of Amendment of the Certificate of
Incorporation filed in the Office of the
Secretary of State of the State of New York on
December 20, 1993.
___________________________________
* Incorporated by reference.
EXHIBIT INDEX (Cont'd)
3-13 -- Certificate of Amendment of the Certificate
of Incorporation filed in the Office of the
Secretary of State of the State of New York on
December 20, 1993.
* 3-14 -- Certificates of the Secretary of the Company
concerning consents dated March 20, 1957 and May
9, 1975 of holders of Serial Preferred Stock with
respect to issuance of certain unsecured
indebtedness.
3-15 -- By-Laws of the Company as amended February 25,
1994.
* 4-1 -- First Mortgage dated as of July 1, 1921 executed
by the Company under its then name of "New York
State Gas and Electric Corporation" to The
Equitable Trust Company of New York, as Trustee
(Chemical Bank is Successor Trustee).
Supplemental Indentures to First Mortgage dated as of July 1, 1921:
* 4-2 -- No. 37 * 4-9 -- No. 74 * 4-16 -- No. 103
* 4-3 -- No. 39 * 4-10 -- No. 75 * 4-17 -- No. 104
* 4-4 -- No. 43 * 4-11 -- No. 80 * 4-18 -- No. 105
* 4-5 -- No. 51 * 4-12 -- No. 81 * 4-19 -- No. 106
* 4-6 -- No. 68 * 4-13 -- No. 83 * 4-20 -- No. 107
* 4-7 -- No. 69 * 4-14 -- No. 99 * 4-21 -- No. 108
* 4-8 -- No. 71 * 4-15 -- No. 102 * 4-22 -- No. 109
Contracts, Amendments, and Letter Agreement with the Power
Authority of the State of New York:
* 10-1 -- Contract UD-4 dated July 28, 1975 (FitzPatrick
Power).
* 10-2 -- Contract PS-2 dated March 28, 1973 (Blenheim-
Gilboa).
* 10-3 -- Letter Agreement dated February 3, 1982 relating
to transmission services.
* 10-4 -- Amendment dated December 21, 1989 to the Letter
Agreement dated February 3, 1982 relating to
transmission services.
* 10-5 -- Contract effective as of February 22, 1989
relating to the purchase of hydroelectric power.
* 10-6 -- Transmission Agreement dated December 12, 1983,
with respect to connection of the Company's
Kintigh (Somerset) Generating Station to the
Niagara-Edic 345 kv transmission system.
___________________________________
* Incorporated by reference.
EXHIBIT INDEX (Cont'd)
* 10-7 -- Amendment dated December 21, 1989 to the
Transmission Agreement dated December 12, 1983
with respect to connection of the Company's
Kintigh (Somerset) Generating Station to the
Niagara-Edic 345 kv transmission system.
* * * * * * * * * *
Coal Sales Agreements and Amendments between New York State
Electric & Gas Corporation, Pennsylvania Electric Company and:
* 10-8 -- Helvetia Coal Company--Agreement made as of
December 22, 1966.
* 10-9 -- Helvetia Coal Company--Amendment made as of April
1, 1974.
* 10-10 -- Helvetia Coal Company--Amendment made as of March
15, 1989.
* 10-11 -- Helvetia Coal Company--Amendment made as of July
25, 1990.
* * * * * * * * * *
* 10-12 -- New York Power Pool Agreement dated July 11,
1985.
* 10-13 -- Transmission Agreement dated January 10, 1990
between New York State Electric & Gas Corporation
and Niagara Mohawk Power Corporation, with
respect to remote load and generation wheeling
service for the Company.
* * * * * * * * * *
Coal Sales Agreement and Amendments between New York State Electric & Gas
Corporation and Consolidation Coal Company:
10-14 -- Agreement dated December 21, 1983.
* 10-15 -- Amendment No. 1 dated as of October 1, 1985.
* 10-16 -- Amendment No. 2 dated as of August 28, 1986.
* * * * * * * * * *
* 10-17 -- Basic Agreement dated as of September 22, 1975
between New York State Electric & Gas Corporation
and others concerning Nine Mile Point Nuclear
Station, Unit No. 2.
* 10-18 -- Nine Mile Point Nuclear Station Unit 2 Operating
Agreement effective as of January 1, 1993 among
New York State Electric & Gas Corporation and
others.
___________________________________
* Incorporated by reference.
EXHIBIT INDEX (Cont'd)
* 10-19 -- Coal Hauling Agreement dated as of March 9, 1983
between Somerset Railroad Corporation and New
York State Electric & Gas Corporation.
(A)* 10-20 -- Retirement Plan for Directors.
(A) 10-21 -- Retirement Plan for Directors Amendment No. 1
(A)* 10-22 -- Form of Deferred Compensation Plan for Directors.
(A) 10-23 -- Deferred Compensation Plan for Directors
Amendment No. 1.
(A)* 10-24 -- Supplemental Executive Retirement Plan
(A)* 10-25 -- Supplemental Executive Retirement Plan Amendment
No. 1.
(A)* 10-26 -- Supplemental Executive Retirement Plan Amendment
No. 2.
(A)* 10-27 -- Supplemental Executive Retirement Plan Amendment
No. 3.
(A)* 10-28 -- Supplemental Executive Retirement Plan Amendment
No. 4.
(A)* 10-29 -- Supplemental Executive Retirement Plan Amendment
No. 5.
(A)* 10-30 -- Supplemental Executive Retirement Plan Amendment
No. 6.
(A)* 10-31 -- Supplemental Executive Retirement Plan Amendment
No. 7.
(A) 10-32 -- Supplemental Executive Retirement Plan Amendment
No. 8.
(A) 10-33 -- Supplemental Executive Retirement Plan Amendment
No. 9.
(A)* 10-34 -- Annual Executive Incentive Compensation Plan.
(A) 10-35 -- Annual Executive Incentive Compensation Plan
Amendment No. 1.
(A) 10-36 -- Annual Executive Incentive Compensation Plan
Amendment No. 2.
(A)* 10-37 -- Performance Share Plan.
(A)* 10-38 -- Performance Share Plan Amendment No. 1.
(A)* 10-39 -- Performance Share Plan Amendment No. 2.
(A)* 10-40 -- Performance Share Plan Amendment No. 3
(A) 10-41 -- Performance Share Plan Amendment No. 4
(A)* 10-42 -- Performance Share Deferred Compensation Plan.
(A) 10-43 -- Performance Share Deferred Compensation Plan
Amendment No. 1
(A)* 10-44 -- Employment Contract for A. E. Kintigh.
(A)* 10-45 -- Agreement with R. Fleming, Jr.
(A) 10-46 -- Employment Agreement for J. A. Carrigg.
(A) 10-47 -- Form of Severance Agreement for Senior Vice
Presidents.
(A) 10-48 -- Form of Severance Agreement for Vice Presidents.
___________________________________
(A) Management contract or compenstory plan or arrangement.
* Incorporated by reference.
EXHIBIT INDEX (Cont'd)
12 -- Computation of Ratio of Earnings to Fixed Charges.
21 -- Subsidiaries.
23 -- Consent of Coopers & Lybrand to incorporation by
reference into certain registration statements.
99-1 -- Form 11-K for New York State Electric & Gas
Corporation Tax Deferred Savings Plan for
Salaried Employees.
99-2 -- Form 11-K for New York State Electric & Gas
Corporation Tax Deferred Savings Plan for Hourly
Paid Employees.